Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

At ~~April 28,~~July 31, 2006, ~~27,576,846~~27,548,346 shares of the registrant’s Common Stock ~~$3-1/6 par value~~ (the only class of Common Stock) were outstanding.


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
Thousands, except per share amounts	2006		2005		2006		2005		2006		2005
Operating revenues:
Gross operating revenues	$	390,391	$	308,777	$	170,979	$	153,667	$	561,370	$	462,444
Less: Cost of sales		255,399		180,608		105,036		92,425		360,435		273,033
Revenue taxes		9,528		7,183		4,196		3,593		13,724		10,776

Net operating revenues		125,464		120,986		61,747		57,649		187,211		178,635

Operating expenses:
Operations and maintenance		28,247		27,195		27,909		26,981		56,156		54,176
General taxes		7,573		6,770		6,066		5,210		13,639		11,980
Depreciation and amortization		15,830		15,195		15,962		15,312		31,792		30,507

Total operating expenses		51,650		49,160		49,937		47,503		101,587		96,663

Income from operations		73,814		71,826		11,810		10,146		85,624		81,972
Other income and expense - net		518		65
Other income and expense – net						410		405		928		470
Interest charges - net of amounts capitalized		9,855		9,128		9,184		8,906		19,039		18,034

Income before income taxes		64,477		62,763		3,036		1,645		67,513		64,408
Income tax expense		23,444		22,876		1,042		505		24,486		23,381

Net income	$	41,033	$	39,887	$	1,994	$	1,140	$	43,027	$	41,027

Average common shares outstanding:
Basic		27,584		27,578		27,563		27,555		27,574		27,568
Diluted		27,632		27,863		27,611		27,834		27,621		27,841
Earnings per share of common stock:
Basic	$	1.49	$	1.45	$	0.07	$	0.04	$	1.56	$	1.49
Diluted	$	1.48	$	1.43	$	0.07	$	0.04	$	1.56	$	1.48


Thousands	March 31, 2006 (Unaudited)			March 31, 2005 (Unaudited)			Dec. 31, 2005			June 30, 2006 (Unaudited)			June 30, 2005 (Unaudited)			Dec. 31, 2005
Assets:
Plant and property:
Utility plant	$	1,890,633		$	1,814,991		$	1,875,444		$	1,914,301		$	1,835,326		$	1,875,444
Less accumulated depreciation		547,635			514,785			536,867			557,632			523,518			536,867

Utility plant - net		1,342,998			1,300,206			1,338,577
Utility plant – net											1,356,669			1,311,808			1,338,577

Non-utility property		40,953			34,157			40,836			41,094			34,862			40,836
Less accumulated depreciation and amortization		6,221			5,408			5,990			6,452			5,581			5,990

Non-utility property - net		34,732			28,749			34,846
Non-utility property – net											34,642			29,281			34,846

Total plant and property		1,377,730			1,328,955			1,373,423			1,391,311			1,341,089			1,373,423

Other investments		54,432			57,198			58,451			54,962			57,978			58,451

Current assets:
Cash and cash equivalents		7,522			2,740			7,143			6,636			40,343			7,143
Accounts receivable		97,859			73,776			84,418			44,782			35,740			84,418
Accrued unbilled revenue		47,764			38,880			81,512			16,657			17,244			81,512
Allowance for uncollectible accounts		(4,526	)		(3,499	)		(3,067	)		(3,814	)		(2,521	)		(3,067	)
Gas inventory		35,906			23,139			77,256			76,667			36,547			77,256
Materials and supplies inventory		9,808			8,262			8,905			9,546			9,295			8,905
Income taxes receivable		—			—			13,234			—			—			13,234
Prepayments and other current assets		57,330			21,429			54,309			47,648			16,048			54,309

Total current assets		251,663			164,727			323,710			198,122			152,696			323,710

Regulatory assets:
Income tax asset		66,757			65,622			65,843			66,757			65,622			65,843
Deferred environmental costs		19,196			7,231			18,880			21,771			13,175			18,880
Deferred gas costs receivable		13,522			12,978			6,974			8,594			7,958			6,974
Unamortized costs on debt redemptions		6,776			7,215			6,881			6,670			7,097			6,881
Unrealized loss on non-trading derivatives											186			—			—
Other		—			6,732			—			—			7,092			—

Total regulatory assets		106,251			99,778			98,578			103,978			100,944			98,578

Other assets:
Fair value of non-trading derivatives		40,879			88,634			178,653			26,926			64,089			178,653
Other		9,102			7,305			9,216			9,448			7,643			9,216

Total other assets		49,981			95,939			187,869			36,374			71,732			187,869

Total assets	$	1,840,057		$	1,746,597		$	2,042,031		$	1,784,747		$	1,724,439		$	2,042,031


Thousands	March 31, 2006 (Unaudited)			March 31, 2005 (Unaudited)			Dec. 31, 2005			June 30, 2006 (Unaudited)			June 30, 2005 (Unaudited)			Dec. 31, 2005
Capitalization and liabilities:
Capitalization:
Common stock	$	87,335		$	87,244		$	87,334		$	383,103		$	87,285		$	87,334
Premium on common stock		296,281			299,900			296,471			—			300,074			296,471
Earnings invested in the business		237,205			214,864			205,687			229,684			207,050			205,687
Unearned stock compensation		—			(809	)		(650	)		—			(756	)		(650	)
Accumulated other comprehensive income (loss)		(1,911	)		(1,818	)		(1,911	)		(1,911	)		(1,818	)		(1,911	)

Total common stock equity		618,910			599,381			586,931			610,876			591,835			586,931
Long-term debt		501,500			483,875			521,500			492,000			521,500			521,500

Total capitalization		1,120,410			1,083,256			1,108,431			1,102,876			1,113,335			1,108,431

Current liabilities:
Notes payable		50,400			10,500			126,700			55,800			—			126,700
Long-term debt due within one year		28,000			15,000			8,000			29,500			27,241			8,000
Accounts payable		91,185			84,693			135,287			76,804			66,472			135,287
Taxes accrued		25,876			22,074			12,725			13,886			8,543			12,725
Interest accrued		11,623			11,171			2,918			2,878			2,953			2,918
Other current and accrued liabilities		38,703			34,320			40,935			36,216			35,312			40,935

Total current liabilities		245,787			177,758			326,565			215,084			140,521			326,565

Regulatory liabilities:
Accrued asset removal costs		173,936			157,975			169,927			178,272			162,350			169,927
Unrealized gain on non-trading derivatives, net		23,937			78,205			171,777			—			54,666			171,777
Customer advances		1,924			1,592			1,847			2,113			1,662			1,847
Other		4,283			—			661			5,744			—			661

Total regulatory liabilities		204,080			237,772			344,212			186,129			218,678			344,212

Other liabilities:
Deferred income taxes		220,568			206,651			222,331			220,439			206,666			222,331
Deferred investment tax credits		4,479			5,155			5,069			4,422			5,200			5,069
Fair value of non-trading derivatives		17,586			10,429			6,876			27,398			9,423			6,876
Other		27,147			25,576			28,547			28,399			30,616			28,547

Total other liabilities		269,780			247,811			262,823			280,658			251,905			262,823

Commitments and contingencies (see Note 7)		—			—			—
Commitments and contingencies (see Note 9)											—			—			—

Total capitalization and liabilities	$	1,840,057		$	1,746,597		$	2,042,031		$	1,784,747		$	1,724,439		$	2,042,031


	Three Months Ended March 31,						Six Months Ended June 30,
Thousands	2006			2005			2006			2005
Operating activities:
Net income	$	41,033		$	39,887		$	43,027		$	41,027
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		15,830			15,195			31,792			30,507
Deferred income taxes and investment tax credits		(3,267	)		(5,822	)		(3,453	)		(5,762	)
Undistributed earnings from equity investments		50			137			(59	)		(54	)
Allowance for funds used during construction		(133	)		(86	)		(333	)		(201	)
Deferred gas costs - net		(6,548	)		(3,427	)
Deferred gas costs – net								(1,620	)		1,593
Gain on sale of non-utility investments								—			(12	)
Contributions to qualified defined benefit pension plans		—			—			—			—
Non-cash expenses related to qualified defined benefit pension plans		1,441			1,159			2,883			2,318
Deferred environmental costs		(2,014	)		(230	)		(3,586	)		(805	)
Income from life insurance investments		(1,383	)		(452	)		(1,797	)		(974	)
Other		4,673			(1,790	)		5,787			(2,925	)
Changes in working capital:
Accounts receivable - net		(11,982	)		(12,077	)
Accrued unbilled revenue - net		33,748			25,521
Accounts receivable and accrued unbilled revenue - net								105,238			72,138
Inventories of gas, materials and supplies		40,447			35,076			(52	)		20,635
Income taxes receivable		13,234			15,970			13,234			15,970
Prepayments and other current assets		(2,249	)		3,644			2,377			7,383
Accounts payable		(44,102	)		(17,785	)		(58,483	)		(36,006	)
Accrued interest and taxes		21,856			20,106			1,121			(1,643	)
Other current and accrued liabilities		(2,231	)		152			(4,719	)		1,144

Cash provided by operating activities		98,403			115,178			131,357			144,333

Investing activities:
Investment in utility plant		(15,002	)		(19,958	)		(38,991	)		(41,428	)
Investment in non-utility property		(106	)		(194	)		(236	)		(889	)
Proceeds from sale of non-utility investments		—			3,001			—			3,001
Proceeds from life insurance		964			—			892			—
Other		1,475			746			4,453			679

Cash used in investing activities		(12,669	)		(16,405	)		(33,882	)		(38,637	)

Financing activities:
Common stock issued, net of expenses		859			2,569			1,556			4,669
Common stock purchased		(398	)		(2,895	)
Common stock repurchased								(1,608	)		(4,861	)
Long-term debt issued								—			50,000
Long-term debt retired								(8,000	)		—
Change in short-term debt		(76,300	)		(92,000	)		(70,900	)		(102,500	)
Cash dividend payments on common stock		(9,516	)		(8,955	)		(19,030	)		(17,909	)

Cash used in financing activities		(85,355	)		(101,281	)		(97,982	)		(70,601	)

Increase (decrease) in cash and cash equivalents		379			(2,508	)		(507	)		35,095
Cash and cash equivalents - beginning of period		7,143			5,248			7,143			5,248

Cash and cash equivalents - end of period	$	7,522		$	2,740		$	6,636		$	40,343


Supplemental disclosure of cash flow information:
Interest paid	$	970		$	970		$	19,052		$	17,796
Income taxes paid	$	—		$	—		$	9,520		$	11,739

Supplemental disclosure of non-cash financing activities:
Conversions to common stock:
7-1/4% Series of Convertible Debentures	$	—		$	152
7-1/4 % Series of Convertible Debentures							$	—		$	286


Thousands	March 31, 2006 (Unaudited)					March 31, 2005 (Unaudited)					Dec. 31, 2005					June 30, 2006 (Unaudited)					June 30, 2005 (Unaudited)					Dec. 31, 2005
Common stock equity:
Common stock	$	87,335				$	87,244				$	87,334				$	383,103				$	87,285				$	87,334
Premium on common stock		296,281					299,900					296,471					—					300,074					296,471
Earnings invested in the business		237,205					214,864					205,687					229,684					207,050					205,687
Unearned compensation		—					(809	)				(650	)				—					(756	)				(650	)
Accumulated other comprehensive income (loss)		(1,911	)				(1,818	)				(1,911	)				(1,911	)				(1,818	)				(1,911	)

Total common stock equity		618,910		55	%		599,381		55	%		586,931		53	%		610,876		55	%		591,835		53	%		586,931		53	%
Long-term debt:
Medium-Term Notes
First Mortgage Bonds:
6.340% Series B due 2005		—					5,000					—					—					5,000					—
6.380% Series B due 2005		—					5,000					—					—					5,000					—
6.450% Series B due 2005		—					5,000					—					—					5,000					—
6.050% Series B due 2006		8,000					8,000					8,000					—					8,000					8,000
6.310% Series B due 2007		20,000					20,000					20,000					20,000					20,000					20,000
6.800% Series B due 2007		9,500					9,500					9,500					9,500					9,500					9,500
6.500% Series B due 2008		5,000					5,000					5,000					5,000					5,000					5,000
4.110% Series B due 2010		10,000					10,000					10,000					10,000					10,000					10,000
7.450% Series B due 2010		25,000					25,000					25,000					25,000					25,000					25,000
6.665% Series B due 2011		10,000					10,000					10,000					10,000					10,000					10,000
7.130% Series B due 2012		40,000					40,000					40,000					40,000					40,000					40,000
8.260% Series B due 2014		10,000					10,000					10,000					10,000					10,000					10,000
4.700% Series B due 2015		40,000					—					40,000					40,000					40,000					40,000
7.000% Series B due 2017		40,000					40,000					40,000					40,000					40,000					40,000
6.600% Series B due 2018		22,000					22,000					22,000					22,000					22,000					22,000
8.310% Series B due 2019		10,000					10,000					10,000					10,000					10,000					10,000
7.630% Series B due 2019		20,000					20,000					20,000					20,000					20,000					20,000
9.050% Series A due 2021		10,000					10,000					10,000					10,000					10,000					10,000
5.620% Series B due 2023		40,000					40,000					40,000					40,000					40,000					40,000
7.720% Series B due 2025		20,000					20,000					20,000					20,000					20,000					20,000
6.520% Series B due 2025		10,000					10,000					10,000					10,000					10,000					10,000
7.050% Series B due 2026		20,000					20,000					20,000					20,000					20,000					20,000
7.000% Series B due 2027		20,000					20,000					20,000					20,000					20,000					20,000
6.650% Series B due 2027		20,000					20,000					20,000					20,000					20,000					20,000
6.650% Series B due 2028		10,000					10,000					10,000					10,000					10,000					10,000
7.740% Series B due 2030		20,000					20,000					20,000					20,000					20,000					20,000
7.850% Series B due 2030		10,000					10,000					10,000					10,000					10,000					10,000
5.820% Series B due 2032		30,000					30,000					30,000					30,000					30,000					30,000
5.660% Series B due 2033		40,000					40,000					40,000					40,000					40,000					40,000
5.250% Series B due 2035		10,000					—					10,000					10,000					10,000					10,000
Convertible Debentures
7-1/4% Series due 2012		—					4,375					—					—					4,241					—

		529,500					498,875					529,500					521,500					548,741					529,500
Less long-term debt due within one year		28,000					15,000					8,000					29,500					27,241					8,000

Total long-term debt		501,500		45	%		483,875		45	%		521,500		47	%		492,000		45	%		521,500		47	%		521,500		47	%

Total capitalization	$	1,120,410		100	%	$	1,083,256		100	%	$	1,108,431		100	%	$	1,102,876		100	%	$	1,113,335		100	%	$	1,108,431		100	%

The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), a regulated utility, and its non-regulated wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation).

The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that ~~the~~ management ~~of the Company~~ considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in ~~the Company’s~~our 2005 Annual Report on Form 10-K (2005 Form 10-K). A significant part of ~~the~~our business ~~of the Company~~ is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

Certain amounts from prior years have been reclassified to conform, for comparison purposes, with the current financial statement presentation. The current year’s presentation of the Consolidated Statements of Income includes the reclassification of revenue taxes as a component of net operating revenues. Revenue taxes are expenses primarily related to the utility’s franchise agreements and are based on gross operating revenues. Since revenue taxes are a direct cost of utility sales, the financial statement classification was changed to improve the presentation of net operating revenues and operating expenses. In prior years, revenue taxes were included under operating expenses as part of taxes other than income taxes. The reclassifications had no impact on the prior ~~years’~~year’s income from operations or net income.

Share Based Payment. Effective Jan. 1, 2006, we adopted Statement of Financial Accounting Standards (SFAS) No. 123R, “Share Based Payment,” using the Modified Prospective Application method without restatement of prior periods. Prior to implementation of SFAS No. 123R, ~~the Company~~we accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Under this method, ~~the Company~~we began to amortize compensation cost for the remaining portion of outstanding awards for which the requisite service was not yet rendered at Jan. 1, 2006. Compensation cost for these awards was based on the fair value of the awards at the grant date aswhich was determined under the intrinsic value method. ~~The Company will~~We determine the fair value of and account for awards that are granted, modified or settled after Jan. 1, 2006 in accordance with SFAS No. 123R. The adoption of SFAS No. 123R did not have a material impact on ~~the Company’s~~our financial condition, results of operations or cash flows. See Note 34 for a ~~detailed~~ discussion of stock-based compensation.

Accounting for Changes and Error Corrections.Effective Jan. 1, 2006, we adopted SFAS No. 154, “Accounting for Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which provides guidance on the accounting for and reporting of accounting changes and error corrections. The statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable

to determine the period-specific effects or the cumulative effect of the change. The guidance provided in APB Opinion No. 20 for reporting the correction of an error in previously issued financial statements remains unchanged and requires the restatement of previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after Dec. 15, 2005. The adoption of SFAS No. 154 did not have a material impact upon ~~the Company’s~~NW Natural’s financial condition, results of operation or cash flows.

Inventory Costs. Effective Jan. 1, 2006, we adopted SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. The adoption of SFAS No. 151 did not have a material impact ~~upon the Company’s~~on NW Natural’s financial condition, results of operations or cash flows.

Purchases and Sales of Inventory with the Same Counterparty. In September 2005, the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) reached a final consensus on Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 requires that two or more legally separate exchange transactions with the same counterparty be combined and considered a single arrangement for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” when the transactions are entered into in contemplation of one another. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. Adoption of this standard isdid not ~~expected to~~ have a material impact on ~~the Company’s~~NW Natural’s financial condition, results of operations or cash flows.

Accounting for Certain Hybrid Instruments.In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Instruments,” which amends SFAS Nos. 133 and 140. SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. The statement is effective for all financial instruments acquired or issued after Jan. 1, 2007. ~~The Company is~~We are in the process of evaluating the effect of the adoption and implementation of SFAS No. 155, which is not expected to have a material impact on ~~its~~our financial condition, results of operation or cash flows.

Variable Interest Entities.In April 2006, the FASB issued a staff position (FSP) interpreting variable interest entities (VIE) under FASB Interpretation No. (FIN) 46(R)-6, “Determining the Variability to be Considered in Applying FIN 46(R)~~-6.~~.” This staff position emphasizes that preparers should use a “by design” approach in determining whether an interest is variable. A “by design” approach includes evaluating whether an interest is variable based on a thorough understanding of the design of the potential VIE, including the nature of the risks that the potential VIE was designed to create and pass along to interest holders in the entity. Consolidation of a VIE by the primary beneficiary is required if it is determined that the VIE does not effectively disperse risks among the parties involved. FSP No. FIN 46(R)-6 must be applied prospectively to all entities with which the ~~Company~~company first becomes involved and to all entities previously required to be analyzed under FIN 46(R) when a reconsideration event has occurred effective on or after July 1, 2006. ~~The Company is~~We are in the process of evaluating the effect of adoption and implementation of FSP No. FIN 46(R)-6, which is not expected to have a material impact on ~~its~~our financial condition, results of operations or cash flows.

Accounting for Uncertainty in Income Taxes.In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB

Statement No. 109,” (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken in a tax return. We must determine whether it is “more-likely-than-not” that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. FIN 48 applies to all tax positions related to income taxes subject to SFAS No. 109, “Accounting for Income Taxes.” The interpretation scopes out income tax positions related to SFAS No. 5, “Accounting for Contingencies.” FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. We do not anticipate that the adoption of this statement will have a material effect on our financial position or results of operations.

At NW Natural’s Annual Meeting held on May 25, 2006, the shareholders approved the Restated Articles of Incorporation, which, among other things, included an amendment, effective May 31, 2006, to eliminate the par value of NW Natural’s common stock. As a result, NW Natural’s “common stock” and “premium on common stock” account balances are now reflected on the balance sheet as “common stock.”

In addition, the shareholders approved an amendment to the Employee Stock Purchase Plan that reserved an additional 200,000 shares of common stock for issuance under the plan.

Effective Jan. 1, 2006, we adopted SFAS No. 123R, “Share Based Payment,” to account for all stock-based compensation plans. Our stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP), the Restated Stock Option Plan (Restated SOP), the Employee Stock Purchase Plan (ESPP) and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership ~~in NW Natural~~ by employees and officers, and, in the case of the NEDSCP, non-employee directors. See Part II, Item 8., Note 4, in the 2005 Form 10-K for a discussion of ~~the Company’s~~NW Natural’s stock-based compensation plans.

Long-Term Incentive Plan. A total of 500,000 shares of ~~the Company’s~~NW Natural’s common stock has been authorized for awards under the terms of the LTIP as stock bonus, restricted stock or performance-based stock awards. At ~~March 31,~~June 30, 2006, performance-based awards on 105,000 shares, based on target, were outstanding, a restricted stock award for 5,000 shares was outstanding, and the remaining 390,000 shares ~~are~~were available for future grants.

Performance-based Stock Awards.At ~~March 31,~~June 30, 2006, the aggregate number of performance-based shares awarded and outstanding under ~~the Company’s~~NW Natural’s LTIP at the threshold, target and maximum levels were as follows:


Year Awarded	Performance Period	Threshold	Target	Maximum	Performance Period	Threshold	Target	Maximum
2004	2004-06	6,750	27,000	54,000	2004-06	6,750	27,000	54,000
2005	2005-07	8,750	35,000	70,000	2005-07	8,750	35,000	70,000
2006	2006-08	10,750	43,000	86,000	2006-08	10,750	43,000	86,000

Total						26,250	105,000	210,000
	Total	26,250	105,000	210,000

For each of the performance periods shown above, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance results relative to ~~the Company’s~~our core and non-core strategies. For awards granted prior to Jan. 1, 2006, ~~the Company recognizes~~we recognize compensation expense and liability for the LTIP

awards based on performance levels achieved, and expected to be achieved, and the estimated market value of the common stock as of the distribution date. For awards granted on or after Jan. 1, 2006, ~~the Company recognizes~~we recognize compensation expense in accordance with SFAS No. 123R, based on performance levels achieved and an estimated fair value using a lattice valuation model. For the quarter and six months ended ~~March 31,~~June 30, 2006, the amount accrued and expensed as compensation under the three LTIP grants was negligible. On a cumulative basis, $0.7 million, $0.6 million and a negligible amount have been accrued for the 2004-06, 2005-07 and 2006-08 performance periods, respectively.

Restricted Stock Awards.Restricted stock awards also have been granted under the LTIP. A restricted stock award consisting of 5,000 shares was granted in 2004, which will vest ratably over the period 2005-09.

Restated Stock Option Plan. ~~The Company has~~We have reserved a total of 2,400,000 shares of Common Stock for issuance under the Restated SOP. At ~~March 31,~~June 30, 2006, options on ~~1,132,600~~1,134,400 shares were available for grant and options to purchase ~~393,700~~388,750 shares were ~~outstanding at March 31, 2006.~~outstanding. Options are granted with an exercise price equal to the market value of the common stock at the date of grant, have 10-year terms and vest ratably over a ~~three~~three- or four-year period following the date of grant. Shares issued under the Restated SOP upon the exercise of stock options are original issue shares. The fair value of ~~the Company’s~~our stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:

The simplified formula for “plain vanilla” options was utilized to determine the expected life as defined and permitted by Staff Accounting Bulletin No. 107. The risk-free interest rate was based on the implied yield currently available on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options. Historical data was employed in order to estimate the volatility factor, measured on a daily basis, for a period equal to the duration of the expected life of the option awards. The dividend yield was based on management’s current estimate for dividend payout at the time of grant. A forfeiture rate of 3 percent was applied to the calculation of compensation ~~expense.~~expense based on historical experience.

The following table presents the effect on net income and earnings per share ~~for~~of outstanding stock options and stock ~~awards prior to the adoption of SFAS No. 123R for the quarter ended March 31, 2005 in addition to the impact on reported earnings in the quarter ended March 31, 2006:~~awards:


Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts	Three Months Ended March 31,
							Three Months Ended June 30,					Six Months Ended June 30,
Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts	2006			2005			2006		2005			2006		2005
	$	41,033		$	39,887		N/A	*	$	1,140		N/A	*	$	41,027
Add: Actual stock-based compensation expense included in reported net income under SFAS No. 123R, net of related tax effects		193			—					—					—
Deduct: Pro forma stock-based compensation expense determined under the fair value based method, net of related tax effects		(193	)		(92	)
Deduct: Pro forma stock-based compensation expense determined under the fair value based method — net of related tax effects										(92	)				(183	)

Pro forma earnings applicable to common stock - basic		41,033			39,795					1,048					40,844
Debenture interest less taxes		—			48					47					94

Pro-forma earnings applicable to common stock - diluted	$	41,033		$	39,843				$	1,095				$	40,938

Basic earnings per share
As reported	$	1.49		$	1.45				$	0.04				$	1.49
Pro forma	$	1.49		$	1.44				$	0.04				$	1.48
Diluted earnings per share
As reported	$	1.48		$	1.43				$	0.04				$	1.48
Pro forma	$	1.48		$	1.43				$	0.04				$	1.47

*	During 2006, we implemented SFAS No. 123R and, therefore, pro forma is as reported.


			Price per Share						Price per Share
	Option Shares		Range		Weighted-Average Exercise Price		Option Shares		Range	Weighted-Average Exercise Price
Balance Outstanding, Dec. 31, 2004	431,470		$	20.25-32.02	$	28.38
Balance Outstanding at Dec. 31, 2005							308,500		$20.25-38.30	$	29.26
Granted	9,000			34.95-38.30		37.18	97,800		34.29		34.29
Exercised	(121,170	)		20.25-31.34		26.59	(15,150	)	20.25-31.34		25.97
Expired	(10,800	)		27.60-31.34		30.79	(2,400	)	31.34		32.82

Balance Outstanding, Dec. 31, 2005	308,500		$	20.25-38.30	$	29.26
Balance Outstanding at June 30, 2006							388,750		$20.25-38.30	$	30.63

Granted	97,800			34.29		34.29
Exercised	(12,000	)		20.25-31.34		24.55
Expired	(600	)		31.34		31.34

Balance Outstanding, Mar. 31, 2006	393,700		$	20.25-38.30	$	30.65

Exercisable, Dec. 31, 2005	189,500		$	20.25-32.02	$	27.63

Exercisable, Mar. 31, 2006	232,850		$	20.25-32.02	$	28.67

Exercisable at Dec. 31, 2005							189,500		$20.25-32.02	$	27.63
Exercisable at June 30, 2006							230,850		$20.25-32.02	$	28.66

The weighted-average grant-date fair value of equity awards granted during 2005 and 2006 was $7.85 and $6.29, respectively. By Dec. 31, 2006, an additional 3,000 shares will vest for a total of ~~235,850~~233,850 exercisable shares at ~~year-end.~~year-end, assuming no forfeitures.

During the ~~first quarter of~~three and six months ended June 30, 2006, ~~$0.2 million of~~ pre-tax compensation expense ~~related~~amounted to $0.2 million and $0.4 million, respectively, relating to options granted under the Restated ~~SOP~~SOP. This expense was recognized in ~~income~~operations and maintenance expense under the fair value method in accordance with SFAS No. 123R. In addition, ~~less than~~ $0.1 million of pre-tax compensation expense related to the ~~Employee Stock Purchase Plan~~ESPP was recognized. As of ~~March 31,~~June 30, 2006, there was ~~$0.8~~$0.7 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2009.

In the ~~first quarter of~~six months ended June 30, 2006, ~~12,000 options~~15,150 option shares were exercised with a total intrinsic value of $0.1 million. Cash of ~~$0.3~~$0.4 million was received for these exercises, and a negligible

related tax benefit was realized. The total intrinsic value of options exercised in the first ~~quarter~~six months of 2005 was ~~$0.6~~$1.0 million, and the total fair value of options that vested in the first ~~quarters~~six months of 2006 and 2005 was $0.3 million and $0.4 million, respectively.

The following table summarizes additional information about stock options outstanding and exercisable at ~~March 31,~~June 30, 2006:


	Outstanding			Exercisable						Outstanding			Exercisable
Range of Exercise Prices	Stock Options	*(In millions)* Aggregate Intrinsic Value		Stock Options	*(In millions)* Aggregate Intrinsic Value		Weighted- Average Exercise Price		Weighted- Average Remaining Life in Years	Stock Options	*(In millions)* Aggregate Intrinsic Value		Stock Options	*(In millions)* Aggregate Intrinsic Value		Weighted- Average Exercise Price		Weighted- Average Remaining Life in Years
$20.25 - $38.30	393,700	$	1.7	232,850	$	1.4	$	28.67	6.3
$20.25 - 38.30										388,750	$	1.6	230,850	$	1.4	$	28.66	6.1

In June 2006, NW Natural redeemed $8.0 million of secured 6.05% Series B Medium-Term Notes, at maturity.

NW Natural enters into forward contracts and other related financial transactions for the purchase of natural gas that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133). NW Natural utilizes derivative financial instruments to manage commodity prices related to natural gas supply requirements (see Part II, Item 8., Note 11, in the 2005 Form 10-K).

At ~~March 31,~~June 30, 2006 and 2005, unrealized gains or losses from mark-to-market valuations of ~~the Company’s~~our derivative instruments were primarily reported as regulatory liabilities or regulatory assets because regulatory mechanisms provide for the realized gains or losses at settlement to be included in utility gas costs, ~~subject~~pursuant to regulatory deferral treatment. The estimated fair values for unrealized gains and losses on derivative instruments outstanding, determined using a discounted cash flow model, ~~for financial swaps and physical derivatives,~~ were as follows:


	Fair Value Gains (Losses)
	March 31,						Dec. 31,			June 30,						Dec. 31, 2005
Thousands	2006			2005			2005			2006			2005			Dec. 31, 2005
Fair Value Gain (Loss)
Fair Value Gain (Loss):
Natural gas commodity-based derivative instruments:
Fixed-price financial swaps	$	26,405		$	87,995		$	173,790		$	1,853		$	62,464		$	173,790
Fixed-price financial call options		—			—			1,871			—			—			1,871
Indexed-price physical supply		(3,079	)		(8,483	)		(5,454	)		(2,571	)		(7,887	)		(5,454	)
Fixed-price physical supply		—			(1,429	)		820			—			—			820
Physical supply contracts with embedded options		566			—			567			335			43			567
Foreign currency forward purchases		45			122			183			197			46			183

Total	$	23,937		$	78,205		$	171,777		$	(186	)	$	54,666		$	171,777

In the ~~first~~second quarter of 2006, NW Natural realized net ~~gains~~losses of ~~$17.5~~$10.5 million from the settlement of ~~natural gas commodity~~fixed-price financial swap ~~and call option~~ contracts, which were recorded as decreases to the cost of gas. Realized losses were offset by lower gas purchase costs from underlying floating rate physical supply contracts. The ~~currency~~ exchange rate in ~~all~~ foreign currency forward ~~purchase~~ contracts is included in ~~our~~ cost of gas at settlement; therefore, no gain or loss was recorded from the settlement of those contracts.

As of ~~March 31,~~June 30, 2006, all natural gas commodity price swap contracts mature no later than Oct. 31, 2008.

~~The Company’s~~Our primary business segment, “Utility,” consists of the distribution and sale of natural gas. Another segment, “Interstate Gas Storage,” represents natural gas storage services provided to interstate and intrastate customers and asset optimization activities performed by an unaffiliated energy marketing company primarily through the use of commodity transactions and releases of temporarily unused portions of NW Natural’s upstream pipeline transportation capacity and gas storage capacity (see Part II, Item 8., Note 2, in the 2005 Form 10-K). The remaining segment, “Other,” primarily consists of non-utility operating activities and non-regulated investments.

The following table presents information about the reportable ~~segments for the three-month periods ended March 31, 2006 and 2005.~~segments. Inter-segment transactions are insignificant.


	Three Months Ended March 31,									Three Months Ended June 30,									Six Months Ended June 30,
Thousands	Utility		Interstate Gas Storage		Other			Total		Utility		Interstate Gas Storage		Other			Total		Utility		Interstate Gas Storage		Other			Total
2006
Net operating revenues	$	122,344	$	3,079	$	41		$	125,464	$	58,047	$	3,671	$	29		$	61,747	$	180,391	$	6,750	$	70		$	187,211
Depreciation and amortization		15,610		220		—			15,830		15,742		220		—			15,962		31,352		440		—			31,792
Income from operations		71,122		2,684		8			73,814
Income (loss) from financial investments		1,383		—		(50	)		1,333
Net income		39,452		1,449		132			41,033
Total assets at March 31, 2006		1,792,955		35,533		11,569			1,840,057
Income (loss) from operations											8,992		3,249		(431	)		11,810		80,114		5,933		(423	)		85,624
Income from financial investments											414		—		109			523		1,797		—		59			1,856
Net income (loss)											214		1,817		(37	)		1,994		39,666		3,266		95			43,027
Total assets at June 30, 2006											1,737,026		36,084		11,637			1,784,747		1,737,026		36,084		11,637			1,784,747

2005
Net operating revenues	$	118,936	$	2,029	$	21		$	120,986	$	55,676	$	1,952	$	21		$	57,649	$	174,612	$	3,981	$	42		$	178,635
Depreciation and amortization		15,031		164		—			15,195		15,149		163		—			15,312		30,180		327		—			30,507
Income (loss) from operations		70,168		1,693		(35	)		71,826		8,559		1,587		—			10,146		78,727		3,280		(35	)		81,972
Income (loss) from financial investments		468		—		(137	)		331
Income from financial investments											506		—		208			714		974		—		71			1,045
Net income		38,844		898		145			39,887		12		844		284			1,140		38,856		1,742		429			41,027
Total assets at March 31, 2005		1,707,832		28,331		10,434			1,746,597
Total assets at June 30, 2005											1,682,429		29,424		12,586			1,724,439		1,682,429		29,424		12,586			1,724,439

The following table provides the components of net periodic benefit cost for the qualified and non-qualified pension plans and other postretirement benefit ~~plans for the three months ended March 31, 2006 and 2005.~~plans. See Part II, Item 8., Note 7, in the 2005 Form 10-K for a discussion of the assumptions used in measuring these costs and benefit obligations.


											Pension Benefits						Other Postretirement Benefits
											Three Months Ended June 30,
Thousands	Pension Benefits						Other Postretirement Benefits				2006			2005			2006		2005
Thousands	Three Months Ended March 31,
	2006			2005			2006		2005
Service cost	$	1,961		$	1,589		$	137	$	114	$	1,961		$	1,589		$	138	$	114
Interest cost		3,758			3,263			283		308		3,758			3,263			283		308
Special termination benefits		—			63			—		—		—			63			—		—
Expected return on plan assets		(4,403	)		(3,530	)		—		—		(4,403	)		(3,531	)		—		—
Amortization of transition obligation		—			—			103		103		—			—			103		103
Amortization of prior service cost		245			223			49		—		245			223			49		—
Recognized actuarial loss		916			481			—		72		916			481			—		72

Net periodic benefit cost	$	2,477		$	2,089		$	572	$	597	$	2,477		$	2,088		$	573	$	597


											Pension Benefits						Other Postretirement Benefits
											Six Months Ended June 30,
Thousands											2006			2005			2006		2005
Service cost											$	3,922		$	3,177		$	275	$	228
Interest cost												7,516			6,526			566		616
Special termination benefits												—			126			—		—
Expected return on plan assets												(8,807	)		(7,061	)		—		—
Amortization of transition obligation												—			—			206		206
Amortization of prior service cost												490			446			98		—
Recognized actuarial loss												1,833			963			—		144

Net periodic benefit cost											$	4,954		$	4,177		$	1,145	$	1,194

~~The Company is~~We are not required to make cash contributions to ~~its~~our qualified non-contributory defined benefit plans in 2006, but cash contributions in the form of ongoing benefit payments will be required for ~~its~~the unfunded non-qualified supplemental pension plans and other postretirement benefit plans in 2006. See Part II, Item 8., Note 7, in the 2005 Form 10-K for a discussion of future payments.

~~NW Natural owns,~~We own, or ~~has~~have previously owned, properties that may require environmental remediation or action. ~~NW Natural accrues~~We accrue all material loss contingencies relating to these properties that ~~it believes~~we believe to be probable of assertion and reasonably estimable. ~~The Company continues~~We continue to study the extent of ~~its~~ potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the range of potential loss beyond the amounts currently accrued, and the

probabilities thereof, cannot be reasonably estimated. ~~NW Natural~~We regularly ~~reviews its~~review our remediation liability for each site where itwe may be exposed to remediation responsibilities. The costs of environmental remediation are difficult to estimate. A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Each of these steps may, over time, involve a number of alternative actions, each of which can change the course of the effort. In certain cases, in addition to NW Natural, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and highly uncertain. The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible

parties. Site investigations and remediation efforts often develop slowly over many years. To the extent reasonably estimable, ~~NW Natural estimates~~we estimate the costs of environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a ~~better~~more likely estimate within this range of probable cost, ~~NW Natural records~~we record the liability at the lower end of this range. It is likely that changes in these estimates will occur throughout the remediation process for each of these sites due to uncertainty concerning ~~NW Natural’s~~our responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. The status of each of the sites currently under investigation is provided below. Also, see Part II, Item 8., Note 12, in the 2005 Form 10-K for a description of these properties and further discussion.

Gasco site. ~~NW Natural owns~~We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). ~~The~~We have been investigating the Gasco site ~~has been under investigation by NW Natural~~ for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, ~~the Company~~we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In the ~~first~~second quarter of 2006, ~~NW Natural~~we accrued an additional ~~$0.2~~$2.1 million ~~for the estimated cost of wells~~ to be used ~~as part~~for the upgrade of the water treatment system in conjunction with source control, replacement of a ~~pilot study~~well, ongoing consultant and investigation fees for in-river groundwater and source ~~control.~~control studies and to cover cost estimates of remedial alternatives identified in the Feasibility Scoping Plan and Ecological and Human Health risk assessment for the most contaminated portion of the site. The liability ~~of $1.1~~balance at June 30, 2006 is $2.6 million, ~~for the Gasco site~~which is at the low end of the ~~range because no amount within the range is considered~~probable and reasonably estimable liability range. We are not able to ~~be more likely than another and~~estimate the high end of ~~the range cannot be estimated.~~a liability range.

Siltronic ~~(formerly Wacker)~~ site. ~~NW Natural~~We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation ~~(formerly Wacker Siltronic Corporation)~~ (the Siltronic site). ~~The liability balance for this site at March 31, 2006~~We have agreed to an addendum to the Voluntary Clean-up Agreement with the ODEQ, which will require additional investigation of manufactured gas plant waste on the Siltronic site. Since the scope of work is ~~negligible (see “Regulatory and Insurance Recovery for Environmental Matters,” below).~~unknown, there is not enough information to reasonably estimate the additional liabilities.

Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Harbor) that includes the area adjacent to the Gasco site and the Siltronic site. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and ~~the Company was~~we were notified that ~~it is~~we are a potentially responsible party. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). ~~Current information~~In the second quarter of 2006, we increased the liability by $0.2 million to $1.6 million in total for our current estimate of liability related to the RI/FS, consultant fees, technical work, and state settlement agreement. Information is not sufficient to

reasonably estimate additional liabilities, if any, or the range of potential liabilities, for environmental remediation and monitoring after the RI/FS work plan is completed, except for the early action removal of a tar deposit in the river sediments discussed below.

In April 2004, ~~the Company~~we entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the ~~river~~Willamette River sediments adjacent to the Gasco site. ~~NW Natural completed the~~The removal of the tar deposit in the Portland Harbor was completed in October 2005, and ~~on Nov. 5,~~in November 2005, the EPA approved the completed project. ~~The estimated~~In the second quarter of 2006, we increased the liability by $0.2 million to $1.4 million for our current remaining cost ~~for~~estimate related to the ~~removal,~~tar deposit, including ~~technical work,~~ oversight, ~~consultants,~~consultant and legal fees and ongoing ~~monitoring is $10 million. To-date, NW Natural~~monitoring. To date, $8.8 million has been spent ~~$8.1 million~~ for work related to the removal of the tar ~~deposit with a remaining estimated liability of $1.9 million.~~deposit.

Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the Oregon Public Utility Commission (OPUC) approved ~~NW Natural’s~~our request for deferral of environmental costs associated with specific ~~sites, including the Gasco, Siltronic and Portland Harbor~~ sites. The authorization, which has been extended through January 2007, ~~and expanded to include the Oregon Steel Mills site,~~ allows ~~NW Natural~~us to defer and seek recovery of unreimbursed environmental costs in a future general rate case. In April 2006, the OPUC authorized ~~NW Natural~~us to accrue interest on deferred balances effective Jan. 27, 2006, subject to an annual demonstration to the OPUC that ~~the Company has~~we have maximized ~~its~~our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. As of ~~March 31,~~June 30, 2006, ~~the Company has~~we have paid a cumulative total of ~~$14.4~~$16.0 million relating to the named sites since the effective date of the deferral authorization.

On a cumulative basis, ~~NW Natural has~~we have recognized a total of ~~$24.0~~$26.6 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, ~~$19.3~~$20.9 million has been spent to-date and ~~$4.7~~$5.7 million is reported as an outstanding liability. ~~At March 31,~~During the second quarter of 2006, ~~the Company~~we increased regulatory assets by $2.6 million for additional environmental cost estimates related to authorized sites, and at June 30, 2006, we had a total environmental regulatory asset of ~~$19.1~~$21.7 million, which includes ~~$14.4~~$16.0 million of total expenditures to date and accruals for additional estimated costs of ~~$4.7~~$5.7 million. ~~The Company believes~~We believe the recovery of these costs is probable through the regulatory process after first pursuing recovery of costs from insurance. ~~The Company~~We also ~~has~~have an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. ~~The Company intends~~We intend to pursue recovery of these environmental costs from ~~its~~our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. ~~The Company considers~~We consider insurance recovery probable based on a combination of factors, including a review of the terms of ~~its~~our insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with similar gas manufacturing facilities, and recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. ~~The Company has~~We have notified the insurance companies but have not yet filed claims for ~~insurance~~ recovery nor have the insurance companies approved or denied coverage of these claims.

~~The Company is~~We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings, including the matters described below and in Part II, Item 8., Note 12, in the 2005 Form 10-K, cannot be predicted with certainty, ~~the Company does~~we do not expect that the ultimate disposition of these matters will have a materially adverse effect on ~~the Company’s~~our financial condition, results of operations or cash flows.

~~Industrial Customers Switching from Transportation to Sales Service.~~Georgia-Pacific Corporation vs. Northwest Natural Gas Company.In the fourth quarter of 2005, the Company settled a dispute with some large industrial customers related to gas costs charged to such customers upon electing to receive gas commodity under sales service instead of arranging for their own supplies through independent third parties. Two formal complaints filed with the OPUC in connection with this matter have been dismissed by the OPUC. The OPUC has also closed the investigation it opened to determine whether the Company had provided adequate information about rates to the industrial customers.

On Feb. 3, 2006, Georgia-Pacific Corporation filed suit against NW Natural ~~(Georgia-Pacific~~(Georgia-Pacific Corporation v. Northwest Natural Gas Company, Case No. CV06-151-PK, United States District Court, District of

Oregon), alleging that ~~NW Natural~~we offered to sell natural gas to Georgia-Pacific under the interruptible sales service provisions of ~~the Company’s~~ Rate Schedule 32 at a commodity rate set at ~~the Company’s~~our Weighted Average Cost of Gas (WACOG). Georgia-Pacific further alleged that itwe accepted this offer and that ~~the Company~~we failed to perform as promised when, in October 2005, ~~NW Natural~~we notified Georgia-Pacific that itwe would have to charge Georgia-Pacific the incremental costs of acquiring gas on the open market. Georgia-Pacific also ~~alleges~~alleged breach of contract, promissory estoppel, fraudulent misrepresentation and breach of the duty of good faith and fair dealing. As

On Feb. 23, 2006, we filed a ~~result, Georgia-Pacific is seeking damages in~~motion for summary judgment on all claims. On June 30, 2006, an ~~amount to be determined at trial but which they expect to be at least $235,000, plus consequential damages in an amount to be determined at trial. Georgia-Pacific further alleges that~~order was issued by ~~failing to sell gas to Georgia-Pacific at~~ the ~~agreed upon price, NW Natural violated Oregon state laws that regulate utility operations, thereby entitling Georgia-Pacific to treble damages and attorney fees.~~

~~Prior to the Georgia-Pacific federal lawsuit being filed, on Jan. 5, 2006, NW Natural sought a declaratory judgment in the Circuit~~U.S. District Court for the ~~State~~District of Oregon ~~(NW Natural Gas Company v.~~dismissing the lawsuit with prejudice and denying all pending motions, if any, as moot. On July 27, 2006, Georgia-Pacific ~~Corporation, Case No. 0601-00116, Multnomah County) declaring that, due~~appealed this ruling to the ~~rapid rise in~~Ninth Circuit Court of Appeals. We do not expect the ~~cost~~outcome of natural gas after hurricanes Katrina and Rita, the Company acted in accordance with its tariffs and all applicable laws when it informed Georgia-Pacific that it would not sell Georgia-Pacific natural gas at its WACOG price. When Georgia-Pacific responded by filing the federal lawsuit described above, and removing the declaratory judgment actionthis appeal to ~~the federal court~~have a material effect on ~~Feb. 2, 2006, NW Natural voluntarily dismissed its suit for declaratory relief, and now all matters between the parties are before the federal court. NW Natural will vigorously contest the claims~~our financial condition or results of ~~Georgia-Pacific.~~operations.

Independent Backhoe Operator Action.Since May 2004 five lawsuits have been filed against the Company by 11 independent backhoe operators who performed backhoe services for the Company under contract. These five lawsuits have been consolidated into one consolidated case,Law and Zuehlke, et. al. v. Northwest Natural Gas Co.,CV-04-728-KI. The consolidated case consolidates the following cases previously reported:Kerry Law and Arnold Zuehlke, on behalf of themselves and all ~~other~~others similarly situated v. Northwest Natural Gas Company ~~(Filed~~(filed May 28, 2004 U.S. Dist. Ct. D. Or. Case No. CV-04-728-KI),Ike Whittlesey, C.G. Nick Courtney, Mark Parrish, John J. Shooter, Roger Whittlesey and Philip Courtney v. Northwest Natural ~~(Filed~~(filed February 18, 2005 U.S. Dist. Ct. D. Or. Case No. CV-05-241-KI),Phillip Courtney v. Northwest Natural(~~Filed~~filed April 12, 2005 U.S. Dist. Ct. D. Or., Case No. CV-05-507-BR), andKenneth Holtmann et. al. v. Northwest Natural(~~Filed~~filed May 20, 2005 U.S. Dist. Ct. D. Or. Case No. 05-CV-00724-BR). The consolidated case also includes a fifth lawsuit filed on January 23, 2006,Larry L. Luethe v. Northwest Natural (U.S. Dist. Ct. D. Or. Case No. CV-06-098-MO).

Plaintiffs in the consolidated case are or have been independent backhoe operators who performed services for the Company under contract. Plaintiffs allege violation of the Fair Labor Standards Act for failure to pay overtime and also assert state wage and hour claims. Plaintiffs claim that they should have been considered “employees,” and seek overtime wages and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys’ fees and costs. Additionally, with the exception of the plaintiff inLarry L. Luethe v. Northwest Natural,plaintiffs allege that the failure to classify them as employees constituted a breach of contract and a tort under and with respect to certain unspecified employee benefits plans, programs and agreements. With the exception of the plaintiff inLarry L. Luethe v. Northwest Natural,plaintiffs seek an unspecified amount of damages for the value of what they would have received under these employee benefit plans if they had been classified as employees. ~~The Company expects~~We expect that the plaintiff inLarry L. Luethe v. Northwest Naturalwill amend his complaint to include ~~these~~this breach of contract and tort claims for unspecified damages.

In October 2005, the court granted the Company’s motion to stay plaintiffs’ claims pending exhaustion of the administrative review process with regard to each of the plans under which plaintiffs allege that they would have been eligible to receive benefits. The litigation is still stayed pending plaintiffs’ exhaustion of the administrative review process. There is insufficient information at this time to reasonably estimate the range of liability, if any, from these claims. ~~NW Natural~~We will vigorously contest these claims and ~~does~~do not expect the outcome of this litigation to have a material effect on ~~its~~our results of operations or financial condition.

Oregon Steel Mills site. In 2004, ~~the Company was~~we were served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case,Oregon Steel Mills, Inc. v. The Port of ~~Portland.~~Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by ~~the Company’s~~NW Natural’s predecessor, Portland Gas & Coke Company, and ten other third-party defendants ~~were~~

disposed of waste oil in a ~~waste oil~~ disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. In March 2005, motions to dismiss by ~~the Company~~NW Natural and other third-party defendants were denied on the basis that the failure of the Port to plead and prove that ~~the Company was~~we were in violation of law was an affirmative defense that may be asserted at trial, but did not provide a sufficient basis for dismissal of the Port’s claim. No date has been set for trial and discovery is ongoing. ~~The Company does~~We do not expect that the ultimate disposition of this matter will have a materially adverse ~~affect~~effect on ~~the Company’s~~our financial condition, results of operations or cash flows.

For the three and six months ended ~~March 31,~~June 30, 2006 and 2005, reported net income was equivalent to total comprehensive income. Items that are excluded from net income and charged directly to common stock equity are accumulated in other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss included in total common stock equity is $1.9 million at ~~March 31,~~June 30, 2006, which is ~~included in common stock equity~~related to our minimum pension liability (see “Consolidated Statements of Capitalization,” above).

On July 26, 2006, we granted a restricted stock award under our LTIP consisting of 6,500 shares, which will vest ratably on March 1, 2007, 2008 and 2009 (see Note 4).

Northwest Natural Gas Company (NW Natural) is a natural gas services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers, operating as a regulated utility business in Oregon and southwest Washington. NW Natural also is engaged in the delivery of interstate and intrastate gas storage services, operating as a non-utility business segment principally regulated by the Federal Energy Regulatory Commission (FERC). The utility is our largest business segment with approximately 98 percent of consolidated total assets. Factors critical to the success of the utility include maintaining a safe and reliable distribution system, acquiring and distributing natural gas supplies and services at a competitive price, and being able to recover the operating and capital costs in the rates charged to customers.

~~The~~NW Natural also is engaged in the delivery of interstate and intrastate gas storage services, operating as a non-utility business segment principally regulated by the Federal Energy Regulatory Commission (FERC). This segment, which represents approximately 2 percent of consolidated total ~~assets. This business segment~~assets, provides services to large customers using storage and transportation capacity and asset optimization services provided under an agreement with an independent energy marketing company. Factors critical to the success of ~~our interstate gas storage~~this segment include being able to develop additional ~~interstate~~ storage capacity at competitive market prices and being able to continue asset optimization services using core utility assets under a regulatory sharing ~~agreement.~~agreements.

In addition to the utility and interstate gas storage business segments, the consolidated financial statements include the accounts of a wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation), and other non-regulated activities, which together are referred to in this report as our Other business segment (see Note 2)7).

The following is management’s assessment of NW Natural’s financial condition including the principal factors that affect our results of operations. The discussion refers to our consolidated activities for the three and six months ended ~~March 31,~~June 30, 2006 and 2005. ~~References~~Unless otherwise indicated, references in this discussion to “Notes” are to the notes to the consolidated financial statements in this report. In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references to earnings per share in this report are on the basis of diluted shares, except where noted otherwise (see Part II, Item 8., Note 1, “Earnings Per Share,” in the 2005 Form 10-K).

There are a number of factors that directly affect our consolidated financial condition and results of operations. The most significant factor we face in the near term is the impact of higher gas prices. While wholesale gas prices ~~have~~had declined in recent months, the current forward market price for natural gas remains higher than the levels we currently ~~have~~ embedded in our utility customers’ rates, which means our customers’ rates are likely to increase this fall. The majority of our gas ~~supply market tightened last year when hurricanes hit parts of~~supplies come from Alberta and British Columbia, while the ~~United States, and they remain tight early this year.~~remainder comes from the U.S. Rocky Mountain region. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers, but further price increases could change our competitive advantage and our customers’ preference for natural gas. If higher gas prices persist, it could affect our ability to add residential and commercial customers and could result in industrial customers shifting their businesses’ energy needs to alternative fuel sources.

Other issues and challenges we could face in the future include unpredictable weather conditions, adverse regulatory actions or policy changes, managing gas supplies, storage and transportation capacity, managing customer growth, maintaining a competitive advantage, managing

environmental risks, and managing interest rate and credit risks. For a more complete discussion of these and other risks, see Part II, Item 7., “Issues, Challenges and Performance Measures,” and Part I, Item 1A., “Risk Factors,” in the 2005 Form 10-K.

To address some of the challenges, we recently initiated a company-wide restructuring of operations with the goal of significantly improving work processes, reducing operating expenses and capital costs, and continuing to strive for excellence in customer service. Our focus has been on developing initiatives to achieve long-term strategic targets. Implementation of these initiatives will involve:

This improved operations model is expected to be implemented over the next several years and to include workforce reductions. These reductions are expected to be accomplished by primarily focusing on a combination of normal attrition and voluntary severance packages. Accordingly, we expect to incur costs of about $1.5 million to $2.0 million in the fourth quarter of 2006 related to a workforce reduction of an estimated 50-100 people, which we expect to largely offset by a combination of cost reductions and gains from non-core asset sales.

In preparing our financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or using different assumptions.

Our most critical estimates or judgments involve regulatory cost recovery, unbilled revenues, derivative instruments, pension assumptions, income taxes and environmental and other contingencies (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2005 Form 10-K). There have been no material changes to the information provided in our 2005 Form 10-K with respect to the application of critical accounting policies and estimates. Management has discussed its estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.

Within the context of our critical accounting policies and estimates, management is not currently aware of any reasonably likely events or circumstances that would result in materially different amounts being reported.

Net income was ~~$41.0~~$2.0 million, or ~~$1.48~~7 cents a share, ~~for the three months ended March 31, 2006, as~~ compared to ~~$39.9~~$1.1 million, or ~~$1.43~~4 cents a share, ~~for~~in the same period ~~last year.~~in 2005. The increase ~~in net income~~ was ~~attributable~~primarily due to improved results from our ~~regulated~~ utility and interstate gas storage segments. InNW Natural’s utility operations contributed $0.2 million, or 1 cent a share, to earnings in the ~~first~~second quarter of 2006, ~~we earned $39.5 million, or $1.43 a share,~~compared to negligible earnings in 2005. Net income from utility operations ~~representing an increase~~is typically low during the second quarter due to the reduced use of ~~$0.7~~natural gas in the spring and early summer. Interstate gas storage operations contributed $1.8 million to earnings in the second quarter of 2006, or 6 cents a share, compared to $0.8 million, or 3 cents a share, ~~over~~in the ~~prior year; and we earned $1.4~~same period in 2005. Other non-utility activities resulted in a negligible loss for the quarter compared to a gain of $0.3 million, or ~~5 cents~~1 cent a share, ~~from interstate gas storage operations representing an increase of $0.5 million, or 2 cents a share, over the prior year.~~

Primary factors affecting ~~first~~second quarter earnings this year over last year include:

~~year’s contribution from gas cost savings, with commodity prices for the two periods mostly hedged and included in customer rates through the annual PGA;~~

For the six months ended June 30, 2006, net income increased 5 percent to $43.0 million, or $1.56 a share, compared to $41.0 million, or $1.48 a share, in the same period in 2005. NW Natural’s utility operations contributed $39.7 million, or $1.44 a share, to earnings in the first six months of 2006, compared to $38.9 million, or $1.40 a share, in 2005. Interstate gas storage operations contributed $3.3 million in the current period, or 12 cents a share, compared to $1.7 million, or 6 cents a share, in 2005. Other non-utility activities resulted in net income of $0.1 million, or less than 1 cent a share, compared to net income of $0.4 million, or 2 cents a share, in 2005.

Primary factors affecting year-to-date earnings this year over last year include:

and a higher percentage of volumes in lower margin rate schedules, partially offset by higher delivered volumes;

Dividends paid on common stock were 34.5 cents and 32.5 cents a share in the three-month periods ended ~~March 31,~~June 30, 2006 and 2005, respectively, and 69 cents and 65 cents a share in the six-month periods ended June 30, 2006 and 2005, respectively. In ~~April~~July 2006, the ~~Company’s~~ Board of Directors declared a dividend of 34.5 cents a share on the common stock, payable ~~May~~Aug. 15, 2006, to shareholders of record on ~~April 28,~~July 31, 2006. The current indicated annual dividend rate is $1.38 a share.

We provide gas utility service in Oregon and Washington, with Oregon representing over 90 percent of our utility revenues. Future earnings and cash flows from utility operations will be determined by, among other factors, our ability to obtain reasonable and timely regulatory treatment for operating expenses and investments in utility plant. See Part II, Item 7., “Results of Operations– Regulatory Matters,” in the 2005 Form 10-K.

On June 30, 2006, the two companies that provide interstate pipeline transportation of our gas supplies filed general rate cases. Williams Gas Pipeline—West, or Northwest Pipeline, filed for a 49 percent rate increase, which would increase our rates by approximately $17.4 million annually. The primary drivers for Northwest Pipeline’s proposed increase are pipeline integrity expenses, mainline and other extension construction, capacity replacement and displacement of supply from the Rocky Mountain region. Gas Transmission Northwest, or GTN, filed for a rate increase of 71 percent, which would increase our rates by approximately $3.1 million. The primary drivers for GTN’s rate increase are return on equity, capital structure, capacity releases and pipeline integrity expenses. Rates for both Northwest Pipeline and GTN are expected to be effective January 1, 2007, subject to credit to customers. Increases in pipeline transportation expenses are subject to our PGA mechanism and are 100 percent passed-through to customers in both Oregon and Washington. See “Rate Mechanisms,” below.

Purchased Gas Adjustment.Rate changes are applied each year under the PGA mechanisms in our tariffs in Oregon and Washington to reflect changes in the costs of natural gas commodity purchased under contracts with gas producers, the application of temporary rate adjustments to amortize balances in deferred regulatory asset and liability accounts and the removal of temporary rate adjustments effective for the previous year.

Under the current PGA mechanisms, we collect an amount for purchased gas costs based on estimates included in rates. If the actual purchased gas costs are higher than the amounts included in rates, we are ~~not allowed~~required to ~~charge customers immediately for~~defer a predetermined percentage of the higher ~~costs but defer the~~ costs and collect them in ~~the future.~~future rates. Similarly, when the actual purchased gas costs are lower than the amounts included in rates, the gas

cost savings are not immediately returned to customers, but ~~are~~a predetermined percentage is deferred and ~~refunded~~credited to customers in future periods. As part of an incentive mechanism in Oregon, wethe impact on current earnings is either a charge to expense for 33 percent of the higher cost of gas sold, or a credit to expense for 33 percent of the lower cost ~~to earnings.~~of gas sold. In Washington, the PGA deferral is ~~currently based on pass-through of~~ 100 percent of the higher or lower actual cost of gas sold.

~~Regulatory and Insurance Recovery for Environmental Matters.~~In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic and Portland Harbor sites. The authorization, which has been extended through January 2007 and expanded to include the Oregon Steel Mills site, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. In April 2006, the OPUC authorized NW Natural to accrue interest on deferred balances effective Jan. 27, 2006, subject to an annual demonstration to the OPUC that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. As of March 31, 2006, we have paid a cumulative total of $14.4 million relating to the named sites since the effective date of the deferral authorization.

On a cumulative basis, NW Natural has recognized a total of $24.0 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $19.3 million has been spent to-date and $4.7 million is reported as an outstanding liability. At March 31, 2006, we had a regulatory asset of $19.1 million which includes $14.4 million of total expenditures to date and accruals for additional estimated costs of $4.7 million. We believe the recovery of these costs is probable through the regulatory process after first pursuing recovery of costs from insurance. We also have an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. We intend to pursue recovery of these environmental costs from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery probable based on a combination of factors, including a review of the terms of our insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with similar gas manufacturing facilities, and recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. We have not filed claims for insurance recovery nor have the insurance companies approved or denied coverage of these claims.

Geo-hazard Program. We entered into a stipulation with the OPUC in 2001 for an enhanced pipeline safety program that included an accelerated bare steel replacement program and a geo-hazard safety program. The geo-hazard safety program included the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed NW Natural to receive deferred accounting rate treatment ~~commencing Oct. 1, 2002,~~ for all costs associated with the ~~programs exceeding $3 million per year.~~geo-hazard program. The authority to defer expenses for costs associated with the geo-hazard program ~~expires~~is scheduled to expire on Dec. 31, 2006.

During 2005, the Oregon legislature passed ~~and Oregon’s Governor signed into law~~ Senate Bill (SB) 408 ~~effective for~~relating to taxes collected by utilities on or after Jan. 1, 2006. This legislation requires the OPUC to establish an annual tax adjustment to ensure that Oregon utilities do not collect in rates more income taxes than they actually pay to government entities. See Part I, Item 1., “Regulation and Rates—Utility Regulation Legislation,” Part ~~IA.~~1A., “Risk Factors,” and Part II, Item 7., “Results of Operations—Regulatory Matters—Utility Regulation Legislation,” in the 2005 Form 10-K. The OPUC continues to develop rules required to implement SB 408 ~~and draft~~with a proposed set of final rules ~~are expected to be filed~~distributed by the OPUC ~~staff in~~on July 25, 2006, ~~with final~~and adoption of final rules scheduled ~~for September 2006. Due~~ to take place in September. We continue to participate in the rulemaking development process, along with members of the OPUC’s staff, interveners and other affected utilities. However, due to the many uncertainties ~~related to the OPUC’s interpretations and rule making~~ with respect to the ~~application~~implementation of the ~~bill’s provisions,~~OPUC’s proposed final rules, we are not able to determine at this time what impact, if any, the new legislation will have on our financial condition, results of operations or cash flows, but the impact may be material.

The following ~~table summarizes~~tables summarize the composition of utility volumes, operating revenues and ~~margin for the three months ended March 31:~~margin:


	Six Months Ended June 30,
Thousands, except degree day data	2006					2005
Utility volumes - therms:
Residential and commercial sales		349,734		55	%		330,405		54	%
Industrial sales and transportation		287,780		45	%		278,505		46	%

Total utility volumes sold and delivered		637,514		100	%		608,910		100	%

Utility operating revenues - dollars:
Residential and commercial sales	$	454,913		82	%	$	372,801		81	%
Industrial sales and transportation		99,631		18	%		79,806		17	%
Other revenues		(38	)	0	%		5,726		1	%

Total utility operating revenues		554,506		100	%		458,333		100	%
Cost of gas sold		360,391					272,945
Revenue taxes		13,724					10,776

Utility net operating revenues (margin)	$	180,391				$	174,612

Utility Margin:⁽¹⁾
Residential sales	$	111,904		62	%	$	104,412		60	%
Commercial sales		45,476		25	%		42,192		24	%
Industrial - firm sales and transportation		6,472		4	%		6,798		4	%
Industrial - interruptible sales and transportation		9,718		5	%		9,729		5	%
Miscellaneous revenues		2,648		2	%		3,229		2	%
Other margin adjustments		3,422		2	%		2,870		2	%

Margin before weather normalization and decoupling		179,640		100	%		169,230		97	%
Weather normalization mechanism		2,686		1	%		2,555		1	%
Decoupling mechanism		(1,935	)	-1	%		2,827		2	%

Utility margin	$	180,391		100	%	$	174,612		100	%

Actual degree days		2,386					2,421

Percent colder (warmer) than average⁽²⁾		(6	%)				(5	%)

(25-year average degree days is used as average)

Our utility results are affected by, among other things, by customer growth and by changes in weather and customer consumption patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers. In order to offset the potential volatility in utility earnings caused by these factors, we obtained OPUC approval of a conservation tariff that

adjusts margin up or down based on changes in residential and commercial customer consumption and a weather normalization mechanism that adjusts customer bills, and our margin, based on above- or below-average temperatures during the winter heating season (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2005 Form 10-K).

Total utility volumes sold and delivered in the second quarter this year over last year decreased 4 percent, while total utility margin increased by 4 percent. Total utility volumes sold and delivered in the first ~~quarter~~half of ~~2006~~this year over last year increased 115 percent ~~compared~~due mainly to ~~the first quarter of 2005. In the three months ended March 31, 2006, weather was 3 percent colder than the comparable period in 2005, but 3 percent warmer than average.~~

~~Customer~~customer growth, which has continued to remain strong, with a net increase of ~~20,967~~19,973 customers since ~~March 31,~~June 30, 2005 or an ~~annual growth rate of 3.5 percent. In the three years ended Dec. 31, 2005, more than 57,000 customers were added, representing an average~~ annual growth rate of 3.3 percent.

~~Results of operations in the residential~~Residential and commercial sales markets are ~~largely~~ impacted by seasonal weather patterns, energy prices, competition from alternative energy sources and economic conditions in our service areas. ~~The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets for the three months ended March 31:~~

~~The primary factors affecting residential and commercial volumes and operating revenues in the first quarter this year over last year include:~~

Typically, 80 percent or more of annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income

is significantly reduced due to the weather normalization mechanism in Oregon. ~~This~~However, this mechanism applies to approximately 92 percent of our Oregon ~~customers. In Washington, our~~ customers, ~~are~~but we do not ~~covered by~~have a weather normalization mechanism in Washington, where ~~approximately~~about 10 percent of our customers are served. SoAs a result, the mechanism does not fully insulate ~~us from~~ utility earnings from volatility due to weather. We also utilize a decoupling mechanism that is intended to break the link between our earnings and the quantity of gas consumed by our customers, so that we do not have an incentive to discourage customers from conserving energy.

The weather normalization mechanism ~~contributed~~recovered a net ~~$1.8~~$0.8 million of margin in the second quarter of 2006 on weather that was 316 percent warmer than ~~normal~~average. This compares to a reduction of $0.7 million to margin in the ~~three month~~same period ~~ended March 31, 2006, compared to $3.2 million~~last year based on weather that was 5 percent warmer than ~~normal~~average. The decoupling mechanism reduced margin by $0.9 million in the second quarter of 2006, compared to a reduction of $2.0 million in the same period last year.

During the six-month period in 2006, the weather normalization mechanism recovered a net $2.7 million of margin based on 6 percent warmer than average weather, compared to a margin recovery of $2.5 million in the same 2005 period based on 5 percent warmer than average weather. The decoupling mechanism reduced margin by $1.9 million in the first ~~three~~six months of 2006, compared to a contribution of $2.8 million in the same period last year.

The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets:

The primary factors affecting residential and commercial volumes and operating revenues in the second quarter this year over last year include:

The primary factors affecting residential and commercial volumes and operating revenues year-to-date this year over last year include:

Total utility operating revenues include accruals for unbilled revenues (gas delivered but not yet billed to customers) based on estimates of gas deliveries from that month’s meter reading dates to month end. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of accrued unbilled revenues compared to the prior ~~year-end.~~period end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenues at the end of each month. At ~~March 31,~~June 30, 2006, accrued unbilled revenue was ~~$47.8~~$16.7 million compared to ~~$38.9~~$17.2 million at ~~March 31,~~June 30, 2005.

The following table summarizes the delivered volumes and utility operating revenues in the industrial ~~market for the three~~market:

Total volumes delivered to industrial sales and transportation customers were down 6.1 million therms, or 4 percent, in the second quarter of 2006 as compared to the same period in 2005. Utility operating revenues were up $0.8 million, or 2 percent, over last year. The higher revenues reflect higher billing rates due to increased gas costs. However, the margin contribution from industrial sales and transportation was flat compared to 2005, primarily driven by a $0.4 million gain recognized from a temporary mark-to-market contract adjustment, offset by a decrease in volumes and a higher percentage of volumes in lower margin rate schedules.

Total volumes delivered to industrial sales and transportation customers were up ~~15.6~~9.3 million therms, or 113 percent, in the ~~first quarter of~~six months ended June 30, 2006, as compared to the same period in ~~2005, and utility~~2005. Utility operating revenues were up ~~$18.9~~$19.8 million, or 4425 percent, over last year. The higher revenues primarily reflect ~~a shift of customers from transportation to sales service and~~ higher billing rates due to increased gas ~~costs.~~costs, plus higher volumes delivered. The margin contribution from industrial sales and transportation ~~customers~~ decreased by $0.3 million, or 42 percent, over 2005, due to a $0.3 million temporary net loss mark-to-market ~~loss~~adjustment related to ~~a temporary~~the valuation of a gas ~~sale contract.~~sales contract and a higher percentage of volumes in lower margin rate schedules, partially offset by higher delivered volumes.

Other revenues include miscellaneous fee income as well as utility revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to gas costs (see Part II, Item 8., Note 1, “Industry ~~Regulation”,~~Regulation,” in the 2005 Form 10-K). Other

revenues ~~decreased~~increased net operating revenues by $1.4 million in the ~~first~~second quarter of 2006, compared to an increase of ~~$5.2~~$0.6 million in the second quarter of 2005. In the first half of 2006, other revenues were negligible, compared to an increase of $5.7 million in the first ~~quarter~~half of 2005. The following table summarizes other revenues by ~~primary category for the three~~major category:

Other revenues in the three months ended ~~March 31,~~June 30, 2006 were ~~$6.6~~$0.8 million ~~lower~~higher than in the three months ended ~~March 31,~~June 30, 2005 primarily due to ~~a decrease~~an increase in ~~deferrals under the decoupling mechanism~~interstate gas storage credits ($~~5.9~~1.3 million) ~~and~~, partially offset by an increase in the amortization of the decoupling deferral balances ($~~1.8~~0.7 million).

Other revenues in the six months ended June 30, 2006 were $5.7 million lower than in the six months ended June 30, 2005 primarily due to a decrease in decoupling deferrals ($4.8 million) and an increase in amortization of decoupling deferral balance ($2.6 million), partially offset by an increase in ~~the weather normalization~~interstate gas storage credits ($1.3 million). For further discussion of regulatory revenue adjustments, ~~($1.1 million). See~~see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2005 Form 10-K.

~~Natural~~Although natural gas commodity prices have increased significantly in ~~recent periods, with~~the last few years, prices had moderated recently, allowing more opportunity to purchase lower-priced spot market gas. During the second quarter and the first six months of 2006, the cost per therm of gas sold was 27 percent and 16 percent higher, respectively, than in the ~~first quarter of 2006 than the first quarter of 2005.~~comparable 2005 periods, reflecting higher natural gas prices and our fixed-price commodity price hedge contracts. The cost per therm of gas sold includes

current gas purchases, gas withdrawn from storage inventory, gains and losses from financial commodity ~~price hedge contracts,~~hedges, margin from off-system gas sales, demand cost balancing adjustments, regulatory deferrals and company ~~use (see Part II, Item 7., “Results of Operations—Comparison of Gas Distribution Operations—Cost of Gas Sold,” in the 2005 Form 10-K).~~use.

We ~~utilize~~use a natural gas commodity-price hedge program under the terms of our Derivatives Policy to help manage our ~~floating~~variable price risk on gas ~~commodity contracts (see “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” above, and Note 4).~~purchases. We realized a net loss from financial hedge ~~gains~~contracts of ~~$17.5~~$10.5 million ~~from this program during~~in the ~~first quarter of~~three months ended June 30, 2006 compared to a gain of $11.3 million during the same period in 2005. During the six months ended June 30, 2006, we realized a net ~~losses~~hedge gain of ~~$1.5~~$7.0 million incompared a gain of $9.8 million during the ~~first three months of~~same period in 2005. Gains and losses relating to the financial hedging of utility gas ~~prices~~purchases are included in cost of ~~gas, which is~~gas. Realized losses were factored into our PGA deferrals and annual rate ~~changes,~~changes. As such, these gains and ~~therefore~~losses have no material impact on net income.

Under our PGA tariff in Oregon, if the cost of gas purchased is higher or lower than the cost embedded in rates, net income ~~from Oregon operations~~ is ~~affected within defined limits by changes~~charged or credited for 33 percent of the difference and the remaining 67 percent is deferred for pass through to customers in ~~purchased~~future rates. Our gas ~~costs (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations—Cost of Gas Sold,”~~purchases in the ~~2005 Form 10-K). Our purchased gas costs in the first quarters~~second quarter of ~~both~~ 2006 ~~and 2005~~ were lower than the costs embedded in rates, ~~which, under~~and our share of the ~~PGA sharing mechanism,~~lower costs increased margin by $1.8 million. For the second quarter of 2005, our gas costs were also lower than the gas costs embedded in rates, and our share of the lower costs increased margin by $0.2 million. In the first six months of 2006, our share of gas cost savings contributed $3.6 million to margin, compared to net savings and a contribution to margin of $2.0 million in the comparable 2005 period. The benefit to customers of gas cost savings amounted to $3.7 million and ~~$1.5 million, respectively.~~

We are also able to use surplus gas supplies under contract but not required for delivery to core market (residential, commercial and industrial firm) customers, due to warmer weather and other factors, to make off-system sales. Under the PGA tariff in Oregon, we retain 33 percent of the margins realized from our off-system gas sales and defer the remaining 67 percent to a regulatory asset or liability account for recovery from, or refund to, customers in future rates. Our share of margin from off-system gas sales in the first quarter of 2006 was a negligible gain compared to a gain of $0.4$7.4 million for the three and six months ended June 30, 2006, respectively.

Based on current forward curve prices, we began moderating our hedging positions compared to prior years, but at the same ~~period~~time we have increased our gas inventory injections into storage while spot prices were lower. Typically, we have a higher percentage of the next gas year’s estimated purchase requirements hedged at this time of year. We may or may not increase our hedging positions to be closer to the level of the past few years, depending on movement in ~~2005.~~forward market prices and our assessment of risk. Having a greater percentage of unhedged gas purchases may subject NW Natural to greater purchased gas cost variability in the future as compared to previous years. See Part II, Item 1A., “Risk Factors,” below. Variations in gas costs are subject to our PGA mechanism. See “Results of Operations—Rate Mechanisms,” above.

~~We earned net~~Net income from our non-utility interstate gas storage business segment in the three and six months ended ~~March 31,~~June 30, 2006 ~~of $1.4~~was $1.8 million and $3.3 million, respectively, after regulatory sharing and income taxes, or 56 cents and 12 cents a ~~share.~~share, respectively. This compares to net income of ~~$0.9~~$0.8 million, or 3 cents a share, and $1.7 million, or 6 cents a share, in the three and six months ended ~~March 31, 2005.~~June 30, 2005, respectively. The increase was primarily due to additional interstate storage capacity brought on line during ~~2006, plus~~mid-year 2005 and an increase in revenues from our asset optimization program with an unaffiliated energy marketing company (see Part II, Item 7., “Results of Operations—Business Segments Other Than Local Gas Distribution—Interstate Gas Storage,” in the 2005 Form 10-K). The segment also began providing intrastate services in February 2006.

~~Our third-party~~Third-party optimization ~~activities~~services are ~~under~~provided pursuant to a contract with an unaffiliated energy marketing company, which ~~optimizes~~assists in the optimization of the value of our assets ~~by engaging in marketing activities~~ primarily through the use of commodity ~~transactions and releases of temporarily unused portions of our upstream pipeline transportation capacity and gas storage capacity.~~transactions. In Oregon, we retain 80 percent of the pre-tax income from interstate storage services and optimization ~~of storage and pipeline transportation capacity~~activities when the costs of ~~such~~the capacity used have not been included in utility rates, ~~and~~or 33 percent of the pre-tax income from such optimization when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a

deferred regulatory account for ~~distribution~~crediting to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from interstate storage services and third-party ~~optimization.~~optimization assistance.

The Other business segment primarily consists of ~~Northwest Natural’s~~a wholly-owned subsidiary, Financial Corporation (see Part II, Item 8., Note 2, “Consolidated Subsidiary Operations and Segment Information,” in the 2005 Form 10-K). Financial Corporation’s operating results for the three months ended June 30, 2006 were ~~negligible losses~~net income of $0.1 million compared to $0.2 million in the second quarter of 2005. For the first ~~quarters~~six months of both 2006 and ~~2005.~~2005, results were net earnings of $0.1 million. In addition, the Other segment includes various other investments, including an investment in a leveraged aircraft lease.

Our net investment balances in Financial Corporation at ~~March 31,~~June 30, 2006 and 2005 were ~~$3.6~~$3.5 and ~~$2.8~~$3.1 million, respectively. The ~~$0.8~~$0.4 million increase ~~was~~ primarily ~~due to~~reflects higher temporary cash investments, partially offset by a decline in the carrying value of long-term investments.

Operations and maintenance expenses in the ~~first~~second quarter of 2006 were ~~$28.2~~$27.9 million, representing a $0.9 million, or 3 percent, increase over the second quarter of 2005. In addition to the costs of serving a 3.3 percent larger customer base, the following contributed to the increase in operations and maintenance expense:

Operations and maintenance expenses in the first six months of 2006 were an increase of $2.0 million, 4 percent higher than in the first ~~quarter~~six months of 2005. The following summarizes the major factors that contributed to the ~~$1.1 million~~ increase in operations and maintenance expense:

General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, increased ~~$0.8~~$0.9 million, or 1216 percent, and $1.7 million, or 14 percent, in the ~~first quarter of~~three- and six- month periods ended June 30, 2006, respectively, over the same ~~period~~periods in 2005. Property taxes increased $0.3 million, or 8 percent, and $0.6 million, or 8 percent, in the three- and six- month periods

ended June 30, 2006, respectively, over the same periods in 2005, due to utility plant additions in 2006 and 2005. Regulatory fees increased $0.5 million ~~or 28 percent, due to~~and $0.9 million in the three- and six-month periods ended June 30, 2006, respectively, over the same periods in 2005, reflecting increased gross operating revenues ~~over~~and the ~~prior year.~~timing impact of payments made in the second quarter of 2006.

Depreciation and amortization expense increased by $0.6 million, or 4 percent, and $1.3 million, or 4 percent, in the ~~three-month period~~three- and six-month periods ended ~~March 31,~~June 30, 2006, respectively, compared to the same ~~period~~periods in 2005. The increased expense ~~is primarily due to additional investments~~reflects ongoing capital expenditures in utility ~~property~~plant that were made primarily to meet continuing customer ~~growth.~~growth and upgrade operating facilities.

The following table summarizes other income and ~~expense-net~~expense—net by primary ~~components for the three months ended March 31:~~components:


							Three months ended June 30,						Six months ended June 30,
Thousands	2006			2005			2006			2005			2006			2005
Gains from company-owned life insurance	$	1,383		$	468
Other income (expense):
Gains from Company-owned life insurance							$	414		$	505		$	1,797		$	973
Interest income		84			46			191			183			275			229
Other non-operating expense		(603	)		(313	)		(215	)		(497	)		(818	)		(810	)
Interest income (charges) on deferred regulatory accounts		(296	)		1
Interest charges on deferred regulatory account balances								(89	)		23			(385	)		24
Earnings from equity investments of Financial Corporation		(50	)		(137	)		109			191			59			54

Total other income and expense – net	$	518		$	65
Total other income							$	410		$	405		$	928		$	470

Other income and expense – net was unchanged in the second quarter of 2006 compared to 2005, and $0.5 million higher in the ~~first quarter of~~six months ended June 30, 2006 compared to the ~~first quarter of~~six months ended June 30, 2005. The increase in the six-month period was due to realized gains in the first quarter from company-owned life insurance, partially offset by higher non-operating expense and higher interest charges on deferred regulatory accounts.

Interest ~~charges-net~~charges—net of amounts capitalized increased $0.3 million, or 3 percent, and $1.0 million, or 6 percent, in the ~~first quarter of~~three- and six-month periods ended June 30, 2006 ~~was $0.7 million, or 1 percent, higher than in the three months ended March 31, 2005. The increase in 2006 was~~and 2005, respectively, due to higher balances of total debt ~~outstanding and higher interest rates during the period.~~outstanding.

The effective corporate income tax rate from operations was ~~36.4~~36.3 percent for each of the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2006 and 2005.

Our goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial

paper maturities (see “Liquidity and Capital Resources,” below). Our consolidated capital structure at ~~March 31,~~June 30, 2006 and 2005 and at Dec. 31, 2005, including short-term debt, was as follows:


	March 31,				Dec. 31, 2005		June 30,				Dec. 31, 2005
	2006		2005		Dec. 31, 2005		2006		2005		Dec. 31, 2005
Common stock equity	51.6	%	54.0	%	47.2	%	51.4	%	51.9	%	47.2	%
Long-term debt	41.8	%	43.7	%	42.0	%	41.4	%	45.7	%	42.0	%
Short-term debt, including current maturities of long-term debt	6.6	%	2.3	%	10.8	%	7.2	%	2.4	%	10.8	%

Total	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

The increase in common stock equity percentage in June of 2006 compared to December of 2005 is primarily related to a reduction of short-term debt of $70.9 million, combined with an increase in common stock equity at June 30, 2006 of $24.0 million. Achieving the target capital structure and maintaining sufficient liquidity are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs.

~~On May 25, 2000, we announced~~The Board has approved a program tofor the repurchase of up to 22.6 million shares, or up to ~~$35~~$85 million in value, of ~~NW Natural’s~~our common ~~stock through a repurchase~~stock. Purchases under this program ~~that has been extended annually. The purchases~~ are made in the open market or through privately negotiated transactions. Since the program’s inception in 2000, we have repurchased ~~777,300~~812,700 shares of common stock at a total cost of ~~$23.5 million. In April 2006, NW Natural’s Board~~$24.7 million, including 47,100 shares at a total cost of ~~Directors extended~~$1.6 million in the ~~share repurchase program through May 31, 2007 and increased the authorization from 2 million shares to 2.6 million shares and increased the dollar limit from $35 million to $85 million~~first six months of 2006. (see “Financing Activities,” below).

At ~~March 31,~~June 30, 2006, we had ~~$7.5~~$6.6 million of cash and cash equivalents compared to ~~$2.7~~$40.3 million at ~~March~~June 30, 2005. The higher balance at June 30, 2005 reflects the temporary investment of a portion of the proceeds from a sale of $50 million of medium-term-notes in the second quarter of 2005. At Dec. 31, 2005, the balance in cash and cash equivalents was $7.1 million, which was comparable to the balance at ~~Dec. 31, 2005.~~June 30, 2006. Short-term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported by committed bank lines of credit totaling $200 million and available through Sept. 30, 2010 (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 2005 Form 10-K). ~~Short-term~~Proceeds from the issuance of long-term debt ~~balances~~ are typically higher at the end of December each year due to seasonal working capital requirements, which reflect the financing of accounts receivable and natural gas inventories during the winter heating season. Short-term debt balances are significantly lower at the end of March as receivables and inventories are converted into cash, which is used to ~~reduce~~finance capital expenditures, refinance maturing short-term ~~debt.~~or long-term debt, and manage the capital structure.

Neither our Mortgage and Deed of Trust nor the indentures under which other long-term debt is issued contain credit rating triggers or stock price provisions that require the acceleration of debt repayment. Also, there are no rating triggers or stock price provisions contained in contracts or other agreements with third parties, except for agreements with certain counterparties under our Derivatives Policy, which require the affected party to provide substitute collateral such as cash, guaranty or letter of credit if credit ratings are lowered to non-investment grade, or in some cases if the mark-to-market value exceeds a certain threshold.

Based on the availability of short-term credit facilities and the ability to issue long-term debt and equity securities, we believe we have sufficient liquidity to satisfy our anticipated cash requirements, including the contractual obligations and investing and financing activities discussed below.

Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we have no material off-balance sheet financing arrangements.

Since Dec. 31, 2005, we entered into a new contract in the amount of $12.4 million for the purchase and installation of automated meter reading equipment. ~~Other than~~Besides this contract and other contracts entered into in the ordinary course of business, there were no material changes to our estimated future contractual obligations during the ~~three~~six months ended ~~March 31,~~June 30, 2006. Our contractual obligations at Dec. 31, 2005 are described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 2005 Form 10-K.

Our primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas purchases and accounts receivable, short-term debt is used to temporarily fund capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by ~~our~~ committed bank lines of credit (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 2005 Form 10-K). We had ~~$50.4~~$55.8 million in commercial paper notes outstanding at ~~March 31,~~June 30, 2006, compared to ~~$10.5 million~~no commercial paper outstanding at ~~March 31,~~June 30, 2005 and $126.7 million outstanding at Dec. 31, 2005. Commercial paper balances are typically lower at the end of the first ~~quarter~~and second quarters compared to year-end resulting from decreases in customer receivables and gas inventories due to ~~collections from higher sales and the withdrawal of gas inventories from storage during the winter heating season~~.seasonality.

We have ~~an agreement~~agreements for unsecured lines of credit totaling $200 million with five commercial banks. The bank lines of credit (bank lines) are available and committed for a term of five years, from Oct. 1, 2005 to Sept. 30, 2010.

Under the terms of these bank lines, we pay upfront fees and annual commitment fees but are not required to maintain compensating bank balances. The interest rates on outstanding loans, if any, under these bank lines are based on then-current market interest rates. All principal and unpaid interest under the bank lines is due and payable on Sept. 30, 2010. There were no outstanding balances on these lines of credit at ~~March 31,~~June 30, 2006 or 2005, or at Dec. 31, 2005.

The lines of credit require us to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of any amounts outstanding. The Company was in compliance with this covenant at June 30, 2006 and at Dec. 31, 2005, and with the equivalent covenant in the prior year’s lines of credit at June 30, 2005.

The table below summarizes our credit ratings from three rating agencies, Standard and Poor’s Rating Services (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings (Fitch).

Each of the rating agencies has assigned usNW Natural an investment grade rating. These credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell or hold ~~our~~NW Natural securities. Each rating should be evaluated independently of any other rating.

Year-over-year changes in our operating cash flows are primarily affected by net income, gas prices, deferred income taxes and other changes in working capital requirements, regulatory deferrals and other cash and non-cash adjustments to operating results. The overall change in cash flow from operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2006 compared to the same period in 2005 was a decrease of ~~$16.8~~$13.0 million, primarily due to a net decrease in cash from working capital ~~changes~~ of ~~$21.9~~$20.9 million. The significant factors contributing to the cash flow changes in the first ~~quarter~~half of 2006 compared to first ~~quarter~~half of 2005 are as follows:

We have lease and purchase commitments relating to ~~our~~ operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources,” above, and Part II, Item 8., Note 12, in the 2005 Form 10-K).

Cash requirements for investing activities in the first ~~three months~~half of 2006 totaled ~~$12.7~~$33.9 million, down from ~~$16.4~~$38.6 million in the same period of 2005. Cash requirements for the acquisition and construction of utility plant totaled ~~$15.0~~$39.0 million, down from ~~$20.0~~$41.4 million in the first ~~quarter~~half of ~~2005.~~2005 due in part to a reductions in public works projects and purchases of general equipment.

Investments in non-utility property during the first ~~three months~~half of 2006 totaled ~~$0.1~~$0.2 million, down from ~~$0.2~~$0.9 million during the first ~~three months~~half of ~~2005.~~2005 due primarily to including amounts related to the start of improvements to the Company’s interstate gas storage facilities in 2005, which were not repeated in 2006.

In January 2005, Financial Corporation received proceeds from the sale of its limited partnership interests in three solar electric generation projects totaling $3.0 million.

Cash used in financing activities in the first ~~three months~~half of 2006 totaled ~~$85.4~~$98.0 million, ~~down~~up from ~~$101.3~~$70.6 million in the same period of 2005. The primary factor contributing to the ~~$15.9~~$27.4 million ~~decrease was the repayment~~increase

results from differences in short-term and long-term debt financings, which consisted of ~~$76.3~~$78.9 million of short-term and long-term debt redemption in 2006, compared to $102.5 million of short-term debt ~~in the first quarter~~redeemed, partially offset by $50 million of ~~2006 compared to $92.0 million in the same period~~long-term debt proceeds in 2005.

~~In 2000, we commenced a program to repurchase shares of~~Under our common stock ~~through a~~ repurchase program ~~that has been extended through May 2007 (see “Capital Structure,” above). We~~we purchased ~~15,600 shares in the first quarter of 2006 at a cost of $0.5 million, compared to 80,500~~47,100 shares at a cost of ~~$2.9~~$1.6 million in the first ~~quarter~~half of 2006, compared to 134,800 shares at a cost of $4.9 million in the first half of 2005.

For the ~~three~~six months and 12 months ended ~~March 31,~~June 30, 2006 and the 12 months ended Dec. 31, 2005, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were ~~7.23, 3.33~~4.47, 3.37 and 3.32, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. Because a significant part of our business is of a seasonal nature, the ratio for the interim period is not necessarily indicative of the results for a full year.

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of ~~the~~ loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” We update our estimates of loss contingencies and related disclosures when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, and we record accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, we recognize an accrued liability at the lower end of the range and disclose the range (see Note 7)9). It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and our financial condition and results of operations could be materially affected by changes in assumptions or estimates related to ~~these~~theses contingencies.

We develop estimates of environmental liabilities and related costs based on currently available information, existing technology and environmental regulations. These costs include investigation, monitoring, and remediation. We received regulatory approval to defer and seek recovery of costs related to certain sites and believe the recovery of these costs is probable through the regulatory

process (see “Results of Operations—Regulatory Developments—Rate Mechanisms,” above). In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” we have recorded a regulatory asset for the amount expected to be recovered. We intend to pursue recovery of these environmental costs from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At ~~March 31,~~June 30, 2006, a cumulative ~~$19.1~~$21.7 million in environmental costs has been recorded as a regulatory asset, including ~~$14.4~~$16.0 million of costs paid to-date and ~~$4.7~~$5.7 million of accrued estimated future environmental ~~costs.~~expenditures. If it is determined that both the insurance recovery and future customer rate recovery of such costs is not probable, then the costs will be charged to expense in the period such determination is made. See Note 7.

In the fourth quarter of 2005, we settled a dispute with some large industrial customers related to gas costs charged to such customers upon electing to receive gas commodity under sales service instead of arranging for their own supplies through independent third parties. Two formal complaints filed with the OPUC in connection with this matter have been dismissed by the OPUC. The OPUC has also closed the investigation it opened to determine whether we had provided adequate information about rates to the industrial customers. We continue to contest claims of Georgia-Pacific Corporation in a related lawsuit more fully described in Note 7.9.

This report and other presentations made by us from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. Our expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable

basis. However, each forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause our actual results to differ materially from those projected, including:

prevailing state and federal governmental policies and regulatory actions, including those of the OPUC and the ~~WUTC,~~Washington Utilities and Transportation Commission (WUTC), with respect to allowed rates of return, industry and rate structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws, and regulations, policies, ~~and~~ orders and laws ~~regulations and orders~~ with respect to the maintenance of pipeline integrity;

All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of NW Natural, also are expressly qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all such factors, nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

~~Item 3.~~

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, weather risk, and interest rate risk. ~~The following describes our exposure to~~For further information regarding these ~~risks.~~risks see Item 7A. in the 2005 Form 10-K and below. Also see Note 6, above, and Part II, Item 1A., “Risk Factors,” below.

We enter into short-term, medium-term and long-term natural gas supply contracts, along with associated short-, medium- and long-term transportation capacity contracts. Historically, we have taken physical delivery of at least the minimum quantities specified in our natural gas supply contracts. These contracts are primarily index-based and subject to annual re-pricing, a process that is intended to reflect anticipated market price trends during the next year. Our PGA mechanisms in Oregon and Washington provide for the recovery from customers of actual commodity costs, except that, for Oregon customers, we absorb 33 percent of the higher cost of gas sold, or retain 33 percent of the lower cost, in either case as compared to the annual PGA price built into customer rates.

~~Market risks related~~Based on current forward curve prices, we began moderating our hedging positions compared to ~~potential adverse changes~~prior years, but at the same time we have increased our gas inventory injections into storage while spot prices were lower. Typically, we have a higher percentage of the next gas year’s estimated purchase requirements hedged at this time of year. We may or may not increase our hedging positions to be closer to the level of the past few years, depending on movement in ~~commodity~~forward market prices ~~foreign exchange rates or counterparty credit quality~~and our assessment of risk. Having a greater percentage of unhedged gas purchases may subject NW Natural to greater purchased gas cost variability in ~~relation~~the future as compared to ~~these financial and physical contracts are discussed in~~previous years. See Part II, Item ~~7A.~~1A., “Risk Factors,” below. Variations in ~~the 2005 Form 10-K and below. Also see Note 4,~~gas costs are subject to our PGA mechanism. See Part I, Item 2.,”Results of Operations—Rate Mechanisms,” above.

Credit exposure to financial derivative counterparties. Based on estimated fair value, our credit exposure to financial derivative counterparties relating to commodity swap contracts was ~~$26.4~~$1.9 million at ~~March 31,~~June 30, 2006. Our Derivatives Policy requires counterparties to have a minimum investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. There were no credit rating downgrades for any of our counterparties during the quarter.

The following table summarizes our credit exposure, based on estimated fair value, and the corresponding counterparty credit ratings. The table uses credit ratings from S&P and Moody’s, reflecting the higher of the S&P or Moody’s rating, or a middle rating if the entity is ~~split rated~~split-rated with more than one rating level ~~difference~~:difference:


	Financial Derivative Exposure by Credit Rating Unrealized Fair Value Gain						Financial Derivative Exposure by Credit Rating Unrealized Fair Value Gain
	March 31,				Dec. 31, 2005		June 30,				Dec. 31,
Thousands	2006		2005		Dec. 31, 2005		2006		2005		2005
AAA/Aaa	$	940	$	—	$	—
AA/Aa		25,465		86,376		172,315	$	1,853	$	61,360	$	172,315
BBB/Baa		—		1,619		3,346		—		1,104		3,346

Total	$	26,405	$	87,995	$	175,661	$	1,853	$	62,464	$	175,661

Credit exposure to customers.Increases in the market price of natural gas are expected to increase our credit exposure to customers. Also, higher gas prices have resulted in some of our largest industrial customers switching from transportation service to sales service. Under transportation service, the customer is purchasing its commodity supplies from an independent third party, while we only provide the transportation service for delivery of that gas to the customer’s premise. Under sales service, the customer is purchasing both its gas commodity supply and transportation service from us. With higher natural gas commodity prices, our credit exposure to large industrial sales customers has ~~increased significantly.~~increased. We monitor and manage the credit exposure of our industrial sales customers through credit policies and

procedures, which are designed to reduce credit risk. These policies and procedures include an ongoing review of credit risks, including changes in the services provided to industrial customers as well as changes in market conditions and customers’ credit quality. Changes in credit risk may require us to obtain additional assurance, such as deposits, letters of credit, guarantees ~~and~~or prepayments to reduce our credit exposure.

We also monitor and manage the credit exposure of our residential and commercial customers. This credit risk is largely mitigated by the nature of our regulated business and reasonably short collection terms, as well as by the consistent application of credit policies and procedures.

As of ~~March 31,~~June 30, 2006, the principal executive officer and principal financial officer of ~~the Company~~NW Natural have evaluated the effectiveness of the design and operation of ~~the Company’s~~NW Natural’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act)). Based upon that evaluation, the principal executive officer and principal financial officer of ~~the Company~~NW Natural have concluded that such disclosure controls and procedures are effective ~~in timely alerting them~~ to ~~any material~~ensure that information ~~relating to the Company and its consolidated subsidiaries~~ required to be disclosed by NW Natural and included in ~~the Company’s~~NW Natural’s reports filed with or furnished to the Securities and Exchange Commission under the Exchange ~~Act.~~Act is accumulated and communicated to NW Natural’s management as appropriate to allow timely decisions regarding required disclosure.

There has been no change in ~~the Company’s~~NW Natural’s internal control over financial reporting that occurred during ~~the Company’s~~NW Natural’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, ~~the Company’s~~NW Natural’s internal control over financial reporting.

~~There are no material changes~~In addition to the other information set forth in ~~risk~~this report, you should carefully consider the factors discussed in ~~the first quarter of 2006. For a discussion of risk factors, see~~ Part I, ~~Item~~“Item 1A.~~, “Risk~~ Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or results of operations. The risks described in our Annual Report on Form ~~10-K.~~

The following table provides information about purchases by us during the quarter ended ~~March 31,~~June 30, 2006 of equity securities that are registered pursuant to Section 12 of the Exchange Act:


Period	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs			(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs⁽²⁾
Balance forward				765,600	$	11,870,463					777,300	$	61,472,462
01/01/06- 01/31/06	1,630	$	35.95	—		—
02/01/06- 02/28/06	26,040	$	34.48	—		—
03/01/06- 03/31/06	2,789	$	33.94	11,700		(398,001	)
04/01/06- 04/30/06								1,434	$	34.35	3,900		(137,301	)
05/01/06- 05/31/06								26,234	$	34.35	31,500		(1,074,464	)
06/01/06- 06/30/06								5,120	$	35.13	—		—

Total	30,459	$	34.51	777,300	$	11,472,462		32,788	$	34.47	812,700	$	60,260,697

shares of common stock at a total cost of ~~$23.5~~$24.7 million. In April 2006, NW Natural’s Board of Directors extended the program through May 31, 2007 and increased the authorization from 2 million shares to 2.6 million shares and increased the dollar limit from $35 million to $85 million.

NW Natural’s Annual Meeting of Shareholders was held in Portland, Oregon on May 25, 2006. At the meeting, four director-nominees were elected, as follows:

The other seven directors whose terms of office as directors continued after the Annual Meeting are: Martha L. (“Stormy”) Byorum, John D. Carter, C. Scott Gibson, Tod R. Hamachek, Richard G. Reiten, Kenneth Thrasher and Russell F. Tromley.

Amendments to the Company’s Employee Stock Purchase Plan were approved by the following vote:

The restatement of the Company’s Restated Articles of Incorporation was approved by the following vote:

The amendment of Article IV of the Company’s Restated Articles of Incorporation was approved by the following vote:

The ratification of the Audit Committee’s appointment of PricewaterhouseCoopers LLP as the Company’s independent public accountants for the year 2006 was approved by the following vote:

There were no broker non-votes except on the proposal to amend the Employee Stock Purchase Plan, as shown above.

In addition to the arrangements described in our Proxy Statement relating to the 2006 Annual Meeting of Shareholders, since the commencement of his employment in 2004, David H. Anderson, Senior Vice President and Chief Financial Officer, has been entitled to a severance benefit equal to one-times annual salary if his employment is terminated by NW Natural without cause prior to Sept. 30, 2007.

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		Page Number

Item 1.	Consolidated Financial Statements

	Consolidated Statements of Income for the three-month and six-month periods ended ~~March 31,~~June 30, 2006 and 2005	31

	Consolidated Balance Sheets at ~~March 31,~~June 30, 2006 and 2005 and Dec. 31, 2005	2

	Consolidated Statements of Cash Flows for the six-month periods ended June 30, 2006 and 2005	4

	Consolidated Statements of ~~Cash Flows for the three-month periods ended March 31, 2006 and 2005~~	6

	~~Consolidated Statements of~~ Capitalization at ~~March 31,~~June 30, 2006 and 2005 and Dec. 31, 2005	75

	Notes to Consolidated Financial Statements	86

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2018

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3638

Item 4.	Controls and Procedures	3739

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	3840

Item 1A.	Risk Factors	3840

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3940

Item 4.	Submission of Matters to a Vote of Security Holders	41

Item 5.	Other Information	42

Item 6.	Exhibits	3942

	Signature	4042


Thousands, except customers	2006			2005
Utility volumes - therms:
Residential sales		176,111			158,931
Commercial sales		103,316			93,349
Change in unbilled sales		(25,528	)		(21,597	)

Total weather-sensitive utility volumes		253,899			230,683

Utility operating revenues - dollars:
Residential sales	$	238,383		$	189,252
Commercial sales		121,700			94,422
Change in unbilled sales		(33,298	)		(25,132	)

Total weather-sensitive utility revenues	$	326,785		$	258,542

Total number of customers (end of period)		623,353			602,388


	Three Months Ended June 30,						Six Months Ended June 30,
Thousands	2006			2005			2006			2005
Utility volumes - therms:
Residential sales		72,047			71,569			248,158			230,500
Commercial sales		48,295			47,508			151,611			140,857
Change in unbilled sales		(25,245	)		(19,884	)		(50,035	)		(40,952	)

Total weather-sensitive utility volumes		95,097			99,193			349,734			330,405

Utility operating revenues - dollars:
Residential sales	$	100,808		$	86,888		$	339,191		$	276,139
Commercial sales		56,863			47,803			178,563			142,226
Change in unbilled sales		(29,909	)		(20,884	)		(62,841	)		(45,564	)

Total weather-sensitive utility revenues	$	127,762		$	113,807		$	454,913		$	372,801


	Three Months Ended June 30,						Six Months Ended June 30,
Thousands	2006			2005			2006			2005
Utility volumes - therms:
Industrial - firm sales		15,924			16,823			40,075			38,561
Industrial - firm transportation		35,348			37,215			65,091			66,312
Industrial - interruptible sales		25,256			35,130			68,444			71,448
Industrial - interruptible transportation		58,358			51,827			115,313			103,161
Change in unbilled sales		(405	)		(448	)		(1,143	)		(977	)

Total utility volumes		134,481			140,547			287,780			278,505

Utility operating revenues - dollars:
Industrial - firm sales	$	15,404		$	13,503		$	39,156		$	31,047
Industrial - firm transportation		1,169			1,027			2,117			2,114
Industrial - interruptible sales		20,384			21,376			55,736			43,989
Industrial - interruptible transportation		1,868			1,745			3,727			3,492
Change in unbilled sales		(739	)		(384	)		(1,105	)		(836	)

Total utility operating revenues	$	38,086		$	37,267		$	99,631		$	79,806


Thousands, except customers	2006		2005
Utility volumes - therms:
Industrial - firm sales		24,151		21,738
Industrial - firm transportation		29,743		29,097
Industrial - interruptible sales		43,188		36,318
Industrial - interruptible transportation		56,955		51,334

Total utility volumes		154,037		138,487

Utility operating revenues - dollars:
Industrial - firm sales	$	23,752	$	17,544
Industrial - firm transportation		948		1,087
Industrial - interruptible sales		35,352		22,613
Industrial - interruptible transportation		1,859		1,747

Total utility operating revenues	$	61,911	$	42,991

Total number of customers (end of period)		944		942


	2006		2005
Risk-free interest rate	4.5	%	4.2	%
Expected life (in years)	6.2		7.0
Expected market price volatility factor	22.8	%	24.6	%
Expected dividend yield	4.0	%	3.6	%


Thousands, except degree day and customer data	2006					2005
Utility volumes - therms:
Residential and commercial sales		253,899		62	%		230,683	62	%
Industrial sales and transportation		154,037		38	%		138,487	38	%

Total utility volumes sold and delivered		407,936		100	%		369,170	100	%

Utility operating revenues - dollars:
Residential and commercial sales	$	326,785		84	%	$	258,542	84	%
Industrial sales and transportation		61,911		16	%		42,991	14	%
Other revenues		(1,440	)	—	%		5,153	2	%

Total utility operating revenues	$	387,256		100	%	$	306,686	100	%

Cost of gas sold		255,384					180,567
Revenue taxes		9,528					7,183

Utility net operating revenues (margin)	$	122,344				$	118,936

Utility margin:⁽¹⁾
Residential sales	$	78,348		64	%	$	70,055	59	%
Commercial sales		31,777		26	%		27,675	23	%
Industrial - firm sales and transportation		3,608		3	%		3,741	3	%
Industrial - interruptible sales and transportation		4,878		4	%		5,058	4	%
Miscellaneous revenues		1,503		1	%		1,898	2	%
Other margin adjustments		1,440		1	%		2,465	2	%

Margin before regulatory mechanism adjustments		121,554		99	%		110,892	93	%
Weather normalization mechanism		1,842		2	%		3,246	3	%
Decoupling mechanism		(1,052	)	(1	%)		4,798	4	%

Utility margin	$	122,344		100	%	$	118,936	100	%

Total number of customers (end of period)		624,297					603,330

Actual degree days		1,814					1,769

Percent colder (warmer) than average (25-year average degree days is used as average)		(3%)					(5%)


	S&P	Moody’s	Fitch
Commercial paper (short-term debt)	A-1+	P-1	F1
Senior secured (long-term debt)	AA-	A2	A+
Senior unsecured (long-term debt)	A+	A3	A
Ratings outlook	Stable	Stable	Stable


Director	Class	Term Expiring	Votes For	Votes Withheld
Timothy P. Boyle	I	2009	23,353,372	345,871
Mark S. Dodson	I	2009	23,249,758	449,485
Randall C. Papé	I	2009	17,658,362	6,040,881
Richard L. Woolworth	I	2009	23,354,765	344,478


				NORTHWEST NATURAL GAS COMPANY
				(Registrant)

Dated: ~~May 4,~~August 3, 2006				/s/ Stephen P. Feltz
				Stephen P. Feltz
				Principal Accounting Officer
				Treasurer and Controller


Document		Exhibit Number
Statement re: Computation of Per Share Earnings		11

Computation of Ratio of Earnings to Fixed Charges		12

Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002		31.1

Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002		31.2

Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		32.1